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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 20142017
OR
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
ENERGY TRANSFER EQUITY, L.P.
(Exact name of registrant as specified in its charter)
Delaware  30-0108820
(state or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
3738 Oak Lawn Avenue,8111 Westchester Drive, Suite 600, Dallas, Texas 7521975225
(Address of principal executive offices) (zip code)
(214) 981-0700
(Registrant’s telephone number, including area code: (214) 981-0700code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class  Name of each exchange on which registered
Common Units  New York Stock Exchange
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes  ý    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes  ¨    No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.
Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  ý    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company¨ Emerging growth company  ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes          ¨          No          ý
The aggregate market value as of June 30, 2014,2017, of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such Common Units on the New York Stock Exchange on such date, was $22.91$14.11 billion. Common Units held by each executive officer and director and by each person who owns 5% or more of the outstanding Common Units have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
At February 18, 2015,16, 2018, the registrant had 538,772,0231,079,145,561 Common Units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None

Table of Contents

TABLE OF CONTENTS
 
PART I
  PAGE
   
ITEM 1.
BUSINESS
1
   
ITEM 1A.
RISK FACTORS
3234
   
ITEM 1B.
UNRESOLVED STAFF COMMENTS
6470
   
ITEM 2.
PROPERTIES
6470
   
ITEM 3.
LEGAL PROCEEDINGS
6570
   
ITEM 4.
MINE SAFETY DISCLOSURES
6673
 
PART II
   
ITEM 5.
MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
6674
   
ITEM 6.
SELECTED FINANCIAL DATA
6875
   
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
6876
   
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
106117
   
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
111120
   
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
111120
   
ITEM 9A.
CONTROLS AND PROCEDURES
111120
   
ITEM 9B.
OTHER INFORMATION
114122
 
PART III
   
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
114123
   
ITEM 11.
EXECUTIVE COMPENSATION
119128
   
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
137142
   
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
139144
   
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
141145
 
PART IV
   
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
142147
ITEM 16
FORM 10-K SUMMARY
148
  
Signatures

143152
 


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Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P. (the “Partnership” or “ETE”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “could,” “believe,” “may,” “will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may vary materially from those anticipated, estimated, projected, forecasted, expressed or expected in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Item 1.A Risk Factors” included in this annual report.
Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document: 
/d  per day
  
AlohaAloha Petroleum, Ltd
AmeriGas AmeriGas Partners, L.P.
   
AOCI accumulated other comprehensive income (loss)
   
AROs asset retirement obligations
   
Bbls  barrels
  
BBtubillion British thermal units
Bcf billion cubic feet
   
Btu  British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy content
CanyonETC Canyon Pipeline, LLC
   
Capacity  capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
   
CDMCDM Resource Management LLC
CDM E&TCDM Environmental & Technical Services LLC
Citrus Citrus, LLC which owns 100% of FGT
Coal HandlingCoal Handling Solutions LLC, Kingsport Handling LLC and Kingsport Services LLC, now known as Materials Handling Solutions LLC
   
CrossCountry CrossCountry Energy, LLC
   
CFTCDakota Access Commodities Futures Trading CommissionDakota Access, LLC
   
DOE U.S.United States Department of Energy
   
DOJUnited States Department of Justice
DOT U.S.United States Department of Transportation
   
Eagle Rock Eagle Rock Energy Partners, L.P.
   
EnterpriseELG Enterprise Products Partners L.P., together with its subsidiariesEdwards Lime Gathering, LLC
   
EPA U.S.United States Environmental Protection Agency
ETC CompressionETC Compression, LLC
   
ETC FEP ETC Fayetteville Express Pipeline, LLC
   
ETC MEPETC Midcontinent Express Pipeline, L.L.C.

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ETC OLP La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
   
ETC TigerETCO ETC Tiger Pipeline,Energy Transfer Crude Oil Company, LLC
   

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ETG Energy Transfer Group, L.L.C.
   
ET InterstateETE Holdings Energy Transfer InterstateETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
   
ETP Energy Transfer Partners, L.P.
ETP Credit FacilityETP’s revolving credit facility
   
ETP GP Energy Transfer Partners GP, L.P., the general partner of ETP
   
ETP Holdco ETP Holdco Corporation
   
ETP LLC Energy Transfer Partners, L.L.C., the general partner of ETP GP
   
ETP Convertible Preferred UnitsETP’s Series A Convertible Preferred Units
ETP Series A Preferred UnitsSeries A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
ETP Series B Preferred UnitsSeries B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Exchange Act Securities Exchange Act of 1934
ExxonMobilExxon Mobil Corporation
   
FDOT/FTE Florida Department of Transportation, Florida’s Turnpike Enterprise
   
FEP Fayetteville Express Pipeline LLC
   
FERC Federal Energy Regulatory Commission
   
FGT Florida Gas Transmission Company, LLC, which owns a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula
   
GAAP accounting principles generally accepted in the United States of America
   
General Partner LE GP, LLC, the general partner of ETE
   
HPC RIGS Haynesville Partnership Co.
HOLPHeritage Operating, L.P.
Hoover EnergyHoover Energy Partners, and its wholly-owned subsidiary, Regency Intrastate Gas LP
   
IDRs incentive distribution rights
   
KMIKinder Morgan Inc.
Lake Charles LNG Lake Charles LNG Company, LLC (previously named Trunkline LNG Company, LLC)
   
LCL Lake Charles LNG Export Company, LLC a subsidiary of ETP and ETE
   
LIBOR London Interbank Offered Rate
   
LNG Liquefiedliquefied natural gas
   
LNG Holdings Lake Charles LNG Holdings, LLC
   
LPGLone Star liquefied petroleum gasLone Star NGL LLC
   
Lone StarLPG Lone Star NGL LLCliquefied petroleum gas
   
MACS Mid-Atlantic Convenience Stores, LLC
   
MBblsthousand barrels
MEP Midcontinent Express Pipeline LLC
   
MGESunoco Logistics Merger Missouri Gas Energy
MGPmanufactured gas plant
MMBtumillion British thermal unitsThe merger of Sunoco Logistics with and into ETP, with ETP surviving the merger as a wholly owned subsidiary of Sunoco Logistics
   
MMcf million cubic feet
   
MTBEmethyl tertiary butyl ether

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NGA Natural Gas Act of 1938
NGPANatural Gas Policy Act of 1978
NEGNew England Gas Company
   
NGL  natural gas liquid, such as propane, butane and natural gasoline
  
NMEDNGPA New Mexico Environmental DepartmentNatural Gas Policy Act of 1978
  

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NYMEX  New York Mercantile Exchange
  
NYSE New York Stock Exchange
   
OSHA Federal Occupational Safety and Health Act
  
OTCover-the-counter
Panhandle Panhandle Eastern Pipe Line Company, LP and its subsidiaries
   
PCBs polychlorinated biphenyls
   
PennTexPennTex Midstream Partners, LP
PEPPermian Express Partners LLC
PEPL Panhandle Eastern Pipe Line Company, LP
PEPL HoldingsPEPL Holdings, LLC
   
PES Philadelphia Energy Solutions
   
PHMSA Pipeline Hazardous Materials Safety Administration
   
PVRPhillips 66 PVRPhillips 66 Partners L.P.
RIGSRegency Intrastate Gas System
RGSRegency Gas Services, a wholly-owned subsidiary of Regency
Preferred UnitsETE’s Series A Convertible Preferred UnitsLP
   
Ranch JV Ranch Westex JV LLC
   
Regency Regency Energy Partners LP
   
Regency GPRetail HoldingsETP Retail Holdings LLC, a subsidiary of ETP
RGS Regency GP LP, the general partnerGas Services, a wholly-owned subsidiary of Regency
   
Regency LLCRIGS Regency GP LLC, the general partner of Regency GPIntrastate Gas System
  
Regency Preferred UnitsRover Regency’s Series A Convertible Preferred Units, the Preferred UnitsRover Pipeline LLC, a subsidiary of a SubsidiaryETP
  
Sea Robin Sea Robin Pipeline Company, LLC
   
SEC Securities and Exchange Commission
   
Southern UnionSouthern Union Company
Southwest Gas Pan Gas Storage, LLC
   
SUGSSunoco GP Southern Union Gas ServicesSunoco GP LLC, the general partner of Sunoco LP
   
Sunoco Logistics Sunoco Logistics Partners L.P.
Sunoco LPSunoco LP (previously named Susser Petroleum Partners, LP)
   
Sunoco Partners Sunoco Partners LLC, the general partner of Sunoco Logistics
   
Susser Susser Holdings Corporation
   
TCEQ Texas Commission on Environmental Quality
   
TitanTitan Energy Partners, L.P.
Transwestern Transwestern Pipeline Company, LLC
   
TRRC Texas Railroad Commission
   
Trunkline Trunkline Gas Company, LLC, a subsidiary of Panhandle
USACUSA Compression Partners, LP
USAC HoldingsUSA Compression Holdings, LLC
WMBThe Williams Companies, Inc.
   
WTI  West Texas Intermediate Crude
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets,

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the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losslosses on extinguishmentextinguishments of debt gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects

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amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.


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PART I

ITEM 1.  BUSINESS
Overview
We were formed in September 2002 and completed our initial public offering in February 2006. We are a Delaware limited partnership with common units publicly traded on the NYSE under the ticker symbol “ETE.”
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, Panhandle, (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco, Inc., Sunoco Logistics, Sunoco LP, Susser and ETP Holdco.Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
During 2014, our consolidated subsidiaries, Trunkline LNG Company, LLC, Trunkline LNG Export, LLC and Susser Petroleum Partners LP, changed their names to Lake Charles LNG Company, LLC, Lake Charles LNG Export, LLC and Sunoco LP, respectively. All references to these subsidiaries throughout this document reflect the new names of those subsidiaries, regardless of whether the disclosure relates to periods or events prior to the dates of the name changes.
In January 2014 and July 2015, the Partnership completed a two-for-one splitsplits of its outstanding common units. All references to units and per unit amounts in this document have been adjusted to reflect the effect of the unit splitsplits for all periods presented.
On March 26, 2012, we acquired all ofThe historical common units for ETP presented in these consolidated financial statements have been retrospectively adjusted to reflect the outstanding shares of Southern Union and contributed our ownership1.5 to one unit-for-unit exchange in Southern Union for a 60% interest in ETP Holdco atconnection with the time of ETP’s acquisition of Sunoco Inc. on October 5, 2012. On April 30, 2013, ETP acquired ETE’s 60% interest in ETP Holdco.Logistics Merger, discussed below.
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency,Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and the Partnership’s ownership of Lake Charles LNG.
At December 31, 2014,January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and RegencySunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as the following:
 ETP Regency
Units held by wholly-owned subsidiaries:   
Common units30,841,069
 57,157,356
ETP Class H units50,160,000
 —
Units held by less than wholly-owned subsidiaries:   
Common units—
 31,372,419
Regency Class F units—
 6,274,483
approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.
The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses, debt service requirements and at ETE’s election, capital contributionsdistributions to ETP and Regency in respect of ETE’s general partner interests in ETP and Regency.its partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries.

1
Table The Parent Company distributes its available cash remaining after satisfaction of Contentsthe aforementioned cash requirements to its unitholders on a quarterly basis.
We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deem prudent to provide liquidity for new capital projects of our subsidiaries or for other partnership purposes.

Organizational Structure
The following chart summarizes our organizational structure as of December 31, 2014.February 7, 2018. For simplicity, certain immaterial entities and ownership interests have not been depicted.
(1)
Pursuant to an agreement between ETE and ETP entered into in December 2014, ETE has agreed to transfer its 45% equity interest in the Bakken Pipeline Project to ETP. This transaction is expected to close in March 2015.


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Significant Achievements in 20142017 and Beyond
Strategic Transactions
Our significant strategic transactions in 20142017 and beyond included the following, as discussed in more detail herein:
Significant Achievements Related to ETE
In January 2015,2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units.
In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.
Significant Achievements Related to ETP
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. As discussed below, in July 2017, ETP contributed a portion of its ownership interest in Dakota Access and ETCO to PEP. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction, with the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. In connection with the merger, Sunoco Logistics was renamed Energy Transfer Partners, L.P. and Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.
In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.
In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and Regency49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.
In January 2018, ETP entered into a definitive mergercontribution agreement as amended(“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which ETP will contribute to USAC 100% of the membership interests of CDM and CDM E&T for aggregate consideration of $1.7 billion, consisting of USAC common units, new USAC Class B units and cash. The Class B units will be substantially similar to USAC common units, except the Class B units will not receive distributions paid with respect to USAC common units prior to the one year anniversary of the closing date of the CDM Contribution Agreement. Each Class B Unit will convert into one USAC common unit on February 18, 2015 (the “Merger Agreement”)such one year anniversary. In connection with the foregoing, ETP entered into a purchase agreement with ETE, ETP LLC, USAC Holdings and, for certain limited purposes, R/C IV USACP Holdings, L.P., pursuant to which RegencyETE and ETP LLC will merge with a wholly-owned subsidiary of ETP, with Regency continuing as the surviving entity and becoming a wholly-owned subsidiary of ETP (the “Regency Merger”). At the effective timeacquire from USAC Holdings (i) all of the Regency Merger (the “Effective Time”), each Regency common unit and Class F unit will be converted intooutstanding interests in the right to receive 0.4066 ETP Common Units, plus a numbergeneral partner of additional ETP Common Units equal to $0.32 per Regency common unit divided by the lesser of (i) the volume weighted average price of ETP Common Units for the five trading days ending on the third trading day immediately preceding the Effective TimeUSAC and (ii) the closing price of ETP Common Units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Regency series A preferred unit will be converted into the right to receive a preferred unit representing a limited partner interest12,466,912 USAC common units for $250 million in ETP, a new class of units in ETP to be established at the Effective Time.cash. The transaction is subject to other customary closing conditions including approval by Regency’s unitholders. The transaction istransactions are expected to close in the second quarterfirst half of 2015.2018, subject to customary closing conditions.
Significant Achievements Related to Sunoco LP
On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.
On March 30, 2017, the Partnership purchased 12 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units was 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate would become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference.
In December 2014, ETP and ETE announced the final terms of a transaction, whereby ETE will transfer 30.8 million ETP CommonJanuary 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units ETE’s 45% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline (collectively, the “Bakken pipeline project”), and $879 million in cash (less amounts funded prior to closingheld by ETE for capital expenditures foran aggregate redemption amount of approximately $313 million. The redemption amount included the Bakken pipeline project) in exchange for 30.8original consideration of $300 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interesta 1% call premium plus accrued and IDRs of Sunoco Logistics. In addition, ETE and ETP agreed to reduce the IDR subsidies that ETE previously agreed to provide to ETP, with such reductions occurring in 2015 and 2016. This transaction is expected to close in March 2015.unpaid quarterly distributions.
In October 2014,On January 23, 2018, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million. The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS.
In August 2014, ETP and Susser completed the mergersale of an indirect wholly-owned subsidiarya portfolio of ETP,approximately 1,030 Sunoco LP operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”).
In July 2014, Regency acquired Eagle Rock’s midstream business for $1.3 billion,related assets, including the issuance of 8.2 million Regency common unitsLaredo Taco Company, to Eagle Rock and the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019 (the “Eagle Rock Acquisition”). The remainder of the purchase price was funded by $400 million in common units issued to ETE and borrowing under Regency’s revolving credit facility. This acquisition complements Regency’s core gathering and processing business, and when combined with the PVR Acquisition, further diversifies Regency’s basin exposure in the Texas Panhandle, east Texas and south Texas.
In March 2014, Regency acquired PVR7-Eleven, Inc. for a totalan aggregate purchase price of $5.7$3.3 billion including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”“7-Eleven Transaction”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which was funded through borrowings under Regency’s revolving credit facility. The PVR Acquisition enhanced Regency’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region.
In February 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE. This transaction was effective as of January 1, 2014.
In 2014, ETP sold 18.9 million of the AmeriGas common units that ETP originally received in connection with the contribution of ETP’s Propane Business to AmeriGas in January 2012.
Business Strategy
Our primary business objective is to increase cash available for distributions to our unitholders by actively assisting our subsidiaries in executing their business strategies by assisting in identifying, evaluating and pursuing strategic acquisitions and growth opportunities. In general, we expect that we will allow our subsidiaries the first opportunity to pursue any acquisition or internal growth project that may be presented to us which may be within the scope of their operations or business strategies. In the future, we may also support the growth of our subsidiaries through the use of our capital resources, which could involve loans, capital

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contributions or other forms of credit support to our subsidiaries. This funding could be used for the acquisition by one of our subsidiaries of a business or asset or for an internal growth project. In addition, the availability of this capital could assist our subsidiaries in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.
Segment Overview
As a result of the Lake Charles LNG Transaction in 2014, ourOur reportable segments were re-evaluated and currently reflect the following reportable segments:are as follows:
•Investment in ETP, including the consolidated operations of ETP;
Investment in Regency,Sunoco LP, including the consolidated operations of Regency;Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the activities of the Parent Company.
The businesses within these segments are described below. See Note 1615 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our reportable segments.
Investment in ETP
ETP’s operations include the following:
Intrastate Transportation and Storage Operations
ETP’s natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities and other pipelines. Through its intrastate transportation and storage operations, ETP owns and operates approximately 7,7007,900 miles of natural gas transportation pipelines with approximately 14.115.2 Bcf/d of transportation capacity and three natural gas storage facilities located in the state of Texas. ETP also owns a 49.99% general partner interest in RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. ETP owns a 16% membership interest in the Trans-Pecos and Comanche Trail pipelines, a 338-mile intrastate pipeline system that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border.
Through ETC OLP, ETP owns the largest intrastate pipeline system in the United States with interconnects to Texas markets and to major consumption areas throughout the United States. ETP’s intrastate transportation and storage operations focus on the transportation of natural gas to major markets from various prolific natural gas producing areas through connections with other pipeline systems as well as through its Oasis pipeline, its East Texas pipeline, its natural gas pipeline and storage assets that are referred to as the ET Fuel System, and its HPL System, which are described below.
ETP’s intrastate transportation and storage operations results are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.
ETP also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. In addition, ETP’s intrastate transportation and storage operations generate revenues from fees charged for storing customers’ working natural gas in ETP’s storage facilities and from margin from managing natural gas for its own account.
Interstate Transportation and Storage Operations
ETP’s natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities and other pipelines. Through its

interstate transportation and storage operations, ETP directly owns and operates approximately 12,800approximately 11,800 miles of interstate natural gas pipelinepipelines with approximately 11.3 Bcf per day10.3 Bcf/d of transportation capacity and has a 50% interest in the joint venture that owns the 185-mile Fayetteville Express pipeline and the 500-mile Midcontinent Express pipeline. ETP also owns a 50% interest in Citrus, which owns 100% of FGT, an approximately 5,4005,360 mile pipeline system that extends from southSouth Texas through the Gulf Coast to south Florida. ETP operates the FEP and FGT joint ventures.
ETP’s interstate transportation and storage operations include Panhandle, which owns and operates a large natural gas open-access interstate pipeline network.  The pipeline network, consisting of the PEPL,Panhandle, Trunkline and Sea Robin transmission systems, serves customers in the Midwest, Gulf Coast and Midcontinent United States with a comprehensive array of transportation and storage services.  In connection with its natural gas pipeline transmission and storage systems, Panhandle has five natural gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma.  Southwest Gas operates four of these fields and Trunkline operates one.
We are currently developing plansThe Rover Pipeline is a new 713-mile natural gas pipeline designed to convert a portiontransport 3.25 Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market. Currently under construction, portions of the Trunklinepipeline are in service transporting gas from processing plants in Eastern Ohio for delivery to other pipeline interconnects in Eastern Ohio as well as the Midwest Hub near Defiance, Ohio, where the gas will be delivered for distribution to crude oil transportation.markets across the United States. The Rover Pipeline Phase 1A and 1B are in service with a capacity of approximately 1.7 Bcf/d.
ETP also owns a 50% interest in the MEP pipeline system, which is operated by KMI, and has the capability to transport up to 1.8 Bcf/d of natural gas.
Gulf States is a small interstate pipeline that uses cost-based rates and terms and conditions of service for shippers wishing to secure capacity for interstate transportation service. Rates charged are largely governed by long-term negotiated rate agreements.
The results from ETP’s interstate transportation and storage operations are primarily derived from the fees ETP earns from natural gas transportation and storage services.
Midstream Operations
The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry consists of natural gas gathering, compression, treating, processing, storage and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

4
Tablewells and the proximity of Contentsstorage facilities to production areas and end-use markets.
The natural gas gathering process begins with the drilling of wells into gas-bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems, that collects natural gas from points near producing wells and transports it to larger pipelines for further transportation.

Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and to continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise might not be produced.
Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is higher in carbon dioxide, hydrogen sulfide or certain other contaminants. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications.
Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable margins for NGLs extracted from the gas stream. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream.
Through ETP’sits midstream operations, ETP owns and operates approximately 7,200 miles of in service natural gas and NGL gathering pipelines, with approximately 5.7 Bcf/d of gathering capacity, 6 natural gas processing plants, 15 natural gas treating facilities and 3 natural gas conditioning facilities with an aggregate processing, treating and conditioning capacity

of approximately 4.612.3 Bcf/d. ETP’s midstream operations focus on the gathering, compression, treating, blending, and processing, of natural gas and its operations are currently concentrated in major producing basins and shales, including the Austin Chalk trend and Eagle Ford Shale in South and Southeast Texas, the Permian Basin in West Texas and New Mexico, the Barnett Shale and Woodford Shale in North Texas, the Bossier Sands in East Texas, the Marcellus Shale in West Virginia and Pennsylvania, and the Haynesville Shale in East Texas and Louisiana. Many of ETP’s midstream assets are integrated with its intrastate transportation and storage assets.
LiquidsETP’s midstream operations also include a 60% interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in South Texas, a 33.33% membership interest in Ranch Westex JV LLC, which processes natural gas delivered from the NGLs-rich shale formations in West Texas, a 75% membership interest in ORS, which operates a natural gas gathering system in the Utica shale in Ohio, and a 50% interest in Mi Vida JV, which operates a cryogenic processing plant and related facilities in West Texas, a 51% membership interest in Aqua – PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, and a 50% interest in Sweeny Gathering LP, which operates a natural gas gathering facility in South Texas.
The results from ETP’s midstream operations are primarily derived from margins ETP earns for natural gas volumes that are gathered, transported, purchased and sold through ETP’s pipeline systems and the natural gas and NGL volumes processed at its processing and treating facilities.
NGL and Refined Products Transportation and Services Operations
ETP’s NGL operations transport, store and execute acquisition and marketing activities utilizing a complementary network of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGL markets.
NGLLiquids transportation pipelines transport mixed NGLs and other hydrocarbons from natural gas processing facilities to fractionation plants and storage facilities. NGL storage facilities are used for the storage of mixed NGLs, NGL products and petrochemical products owned by third-partiesthird parties in storage tanks and underground wells, which allow for the injection and withdrawal of such products at various times of the year to meet demand cycles. NGL fractionators separate mixed NGL streams into purity products, such as ethane, propane, normal butane, isobutane and natural gasoline.
Through ETP’s liquidsNGL and refined products transportation and services operations ETP has a 70% interest in Lone Star, which ownsinclude approximately 2,0004,300 miles of NGL pipelines, with an aggregate transportation capacity of approximately 388,000 Bbls/d, three NGL processing plants with an aggregate processing capacity of approximately 904 MMcf/d, fourfive NGL and propane fractionation facilities with an aggregate capacity of 325,000 Bbls/545 MBbls/d and NGL storage facilities with aggregate working storage capacity of approximately 53 million Bbls. ThreeFour of ETP’s NGL and propane fractionation facilities and the50 million Bbls of ETP’s NGL storage facilitiescapacity are located at Mont Belvieu, Texas, one NGL fractionation facility is located in Geismar, Louisiana, and the segment has 3 million Bbls of salt dome storage capacity near Hattiesburg, Mississippi. ETP is currently constructing a fifth and sixth fractionator in Mont Belvieu, Texas, which are expected to be operational in the third quarter of 2018 and the second quarter of 2019, respectively. The NGL pipelines primarily transport NGLs from the Permian and Delaware basins and the Barnett and Eagle Ford Shales to Mont Belvieu. ETP
Terminalling services are facilitated by approximately 7 million Bbls of NGLs storage capacity, including approximately 1 million Bbls of storage at ETP’s Nederland, Texas terminal facility, 1 million Bbls of storage at our Inkster, Michigan terminal facility and 5 million Bbls at ETP’s Marcus Hook, Pennsylvania terminal facility (the “Marcus Hook Industrial Complex”). These operations also ownssupport ETP’s NGLs blending activities, including the use of ETP’s patented butane blending technology.
Liquids transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and operatescompetitive with regional regulated pipelines.
NGL fractionation revenue is principally generated from fees charged to customers under take-or-pay contracts. Take-or-pay contracts have minimum payment obligations for throughput commitments requiring the customer to pay regardless of whether a fixed volume is fractionated from raw make into purity NGL products. Fractionation fees are market-based, negotiated with customers and competitive with other fractionators along the Gulf Coast.
NGL storage revenues are derived from base storage fees and throughput fees. Base storage fees are firm take or pay contracts on the volume of capacity reserved, regardless of the capacity actually used. Throughput fees are charged for providing ancillary services, including receipt and delivery and custody transfer fees.
This segment also includes revenues earned from the marketing of NGLs and processing and fractionating refinery off-gas. Marketing of NGLs primarily generates margin from selling ratable NGLs to end users and from optimizing storage assets.

Processing and fractionation of refinery off-gas margin is generated from a percentage-of-proceeds of O-grade product sales and income sharing contracts, which are subject to market pricing of olefins and NGLs.
ETP’s refined products operations provide transportation and terminalling services, through the use of approximately 2742,200 miles of NGLrefined products pipelines including a 50% interest in the joint venture that owns the Liberty pipeline, anand approximately 87-mile NGL pipeline and the recently converted 83-mile Rio Bravo crude oil pipeline.
40 active refined products marketing terminals. ETP’s Investment in Sunoco Logistics
ETP’s interests in Sunoco Logistics consist of a 1.9% general partner interest, 100% of the IDRs and 67.1 million Sunoco Logistics common units representing 29.7% of the limited partner interests in Sunoco Logistics as of December 31, 2014. Because ETP controls Sunoco Logistics through its ownership of the general partner, the operations of Sunoco Logisticsmarketing terminals are consolidated into ETP.
Sunoco Logistics owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets which are used to facilitate the purchase and sale of crude oil and refined petroleum products pipelineslocated primarily in the northeast, midwest and southwest United States, with approximately 8 million Bbls of refined products storage capacity. ETP’s refined products operations include its Eagle Point facility in New Jersey, which has approximately 6 million Bbls of refined products storage capacity. The operations also include ETP’s equity ownership interests in four refined products pipeline companies. The operations also perform terminalling activities at ETP’s Marcus Hook Industrial Complex. ETP’s refined products operations utilize its integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions ofin the United States. In 2013, Sunoco Logistics expanded its
Crude Oil Transportation and Services Operations
ETP’s crude oil operations of pipelineprovide transportation, terminalling and acquisition storage and marketing of NGLs. In addition, Sunoco Logistics has ownership interests in several product pipeline joint ventures.
Sunoco Logistics’services to crude oil pipelines transportmarkets throughout the southwest, midwest and northeastern United States. Included within the operations are approximately 9,360 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States principallyand equity ownership interests in Oklahoma and Texas. Sunoco Logistics’two crude oil pipelines consist of approximately 5,300 miles ofpipelines. ETP’s crude oil trunk pipelines for high-volume, long-distance transportation and approximately 500 miles of crude oil gathering lines that supply the trunk pipelines.
Sunoco Logistics’ crude oil acquisition and marketing business gathers, purchases, markets and sells crude oil principally in the mid-continent United States, utilizing its proprietary fleet of approximately 335 crude oil transport trucks and approximately 135 crude oil truck unloading facilities as well as third-party assets.
Sunoco Logistics’ terminal facilities consist of crude oil, refined products and NGL terminals which receive products from pipelines, barges, railcars, and trucks and distribute them to third parties and certain affiliates, who in turn deliver them to end-users and retail outlets. Sunoco Logistics’ terminal facilitiesterminalling services operate with an aggregate storage capacity of approximately 4833 million barrels,Bbls, including the 25approximately 26 million barrelBbls at ETP’s Gulf Coast terminal in Nederland, Texas and approximately 3 million Bbls at ETP’s Fort Mifflin terminal complex in Pennsylvania. ETP’s crude oil terminal; the 6 million barrel Eagle Point, New Jersey refined productsacquisition and marketing activities utilize its pipeline and terminal assets, its proprietary fleet crude oil terminal; the 3 million barrel Marcus Hook, Pennsylvania refined productstractor trailers and NGL facility (the “Marcus Hook Industrial Complex”); approximately 39 active refined products marketing terminals located in the northeast, midwest and southwest United States; and refinery terminals located in the northeast United States.
Sunoco Logistics’ product pipelines transport refined products and NGLs including multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel) and LPGs (such as propane and butane) from refineries to markets. Sunoco Logistics’ products pipelines consist of approximately 2,400 miles of refined products and NGL pipelines and joint venture interests in four products pipelines in selected areas of the United States.

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Retail Marketing Operations
ETP’s retail marketing business operations are conducted through various wholly-owned subsidiariestruck unloading facilities, as well as through Sunoco LP, which ETP controls throughthird-party assets, to service crude oil markets principally in the mid-continent United States.
Revenues throughout ETP’s crude oil pipeline systems are generated from tariffs paid by shippers utilizing its ownership oftransportation services. These tariffs are filed with the general partner.FERC and other state regulatory agencies, as applicable.
ETP’s retailcrude oil acquisition and marketing activities include the gathering, purchasing, marketing and wholesale distributionselling of crude oil primarily in the mid-continent United States. Specifically, the crude oil acquisition and marketing activities include:
purchasing crude oil at both the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;
storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);
buying and selling crude oil of different grades, at different locations in order to maximize value;
transporting crude oil using the pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated by third parties; and
marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
In November 2016, ETP purchased a crude oil acquisition and marketing business from Vitol, with operations includebased in the following activities conductedPermian Basin, Texas. Included in 30 states, primarily on the east cost, midwest and south regions of the United States:
Sale of motor fuel (gasoline and diesel) and merchandise at company-operated retail locations and branded convenience stores.
Distribution of gasoline, diesel and other petroleum products to convenience stores, independent dealers, distributors and other commercial customers.acquisition was a significant acreage dedication from an investment-grade Permian producer.
ETP’s Other Operations and Investments
ETP’s other operations and investments include the following:
ETP owns an equity method investment in Regency consistinglimited partner units of the RegencySunoco LP. As of December 31, 2017, ETP’s investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units and Class Fon February 7, 2018, ETP’s investment consists of 26.2 million units, received by Southern Union (now Panhandle) in exchange for the contributionrepresenting 31.8% of its interest in Southern Union Gathering Company, LLC to Regency on April 30, 2013.Sunoco LP’s total outstanding common units.
ETP’s wholly-owned subsidiary, Sunoco, Inc., owns an approximate 33% non-operating interest in PES, a refining joint venture with The Carlyle Group, L.P. (“The Carlyle Group”), which owns a refinery in Philadelphia.
PES Holdings, LLC ("PES Holdings") and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018 in the United States Bankruptcy Court for the District of Delaware to implement a prepackaged reorganization plan that will allow its shareholders to retain a minority stake. PES Holdings' Chapter 11 Plan (“Plan”) proposes to inject $260 million in new capital into PES Holdings, cut debt service obligations by about $35 million per year and remove debt maturities before 2022.  Under that Plan, PES Holdings’ non-debtor parent, PES, in which ETP holds an indirect 33% equity interest, will provide a $65 million cash contribution in exchange for a 25% stake in the reorganized debtor. After the restructuring, the proportionate ownership of Carlyle Group, L.P. and ETP in PES Holdings will be 16.26% and 8.13%, respectively. Finally,

Sunoco Inc. hasLogistics Partners Operations L.P. (“SXL Operating Partnership”), a supply contract for gasolinesubsidiary of ETP, is providing an additional $75 million exit loan ranked pari passu with the other debt.  SXL Operating Partnership’s, PES Holdings’ and diesel produced atETP’s current contracts will be assumed, without any impairments, in the refinery for its retail marketing business.Chapter 11, and business operations will continue uninterrupted.  The financial reorganization is expected to complete in the first quarter of 2018.
ETP conducts marketing operations in which it markets the natural gas that flows through its gathering and intrastate transportation assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through its assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other suppliers and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices of natural gas, less the costs of transportation. For the off-system gas, ETP purchases gas or acts as an agent for small independent producers that may not have marketing operations.
ETP owns all of the outstanding equity interests of a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.
ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of Energy Transfer Technologies, Ltd. (“ETT”). ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’s other operations.
ETP owns a 40% interest in the parent of LCL, which is developing a LNG liquefaction project.
Investment in Regency
Regency’s operations include the following:
Gathering and Processing Operations
Regency provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems, and the gathering of oil (crude and/or condensate, a lighter oil) received from producers, the gathering and disposing of salt water, and natural gas and NGL marketing and trading. These operations also include Regency’s 60% interest in Edwards Lime Gathering LLC, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, Regency’s 33.33% membership interest in Ranch Westex JV LLC, which processes natural gas delivered from the NGLs-rich shale formations in west Texas, Regency’s 50% interest in Sweeny Gathering LP, which operates a natural gas gathering facility in south Texas, Regency’s 51% membership interest in Aqua - PVR Water Services, LLC, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, Regency’s 75% membership interest in Ohio River System LLC, which will operate a natural gas gathering system in the Utica shale in Ohio, and Regency’s 50% interest in Mi Vida JV LLC, which will operate a cryogenic processing plant and related facilities in west Texas.

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Natural Gas Transportation Operations
Regency owns a 49.99% general partner interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. These operations also include Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
NGL Services Operations
Regency owns a 30% membership interest in Lone Star with ETP owning the remaining 70% membership interest.
Contract Services Operations
Regency owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. RegencyETP also owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. These assets are primarily owned through CDM and CDM E&T. As discussed in “Recent Developments” in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in January 2018, ETP entered into an agreement to contribute these assets to USAC.
ETP is involved in the management of coal and natural resources properties and the related collection of royalties. ETP also earns revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. These operations also include end-user coal handling facilities.
ETP also owns PEI Power Corp. and PEI Power II, which own and operate a facility in Pennsylvania that generates a total of 75 megawatts of electrical power.
Investment in Sunoco LP
Sunoco LP is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites.
Wholesale Operations
Sunoco LP is a wholesale distributor of motor fuels and other petroleum products which Sunoco LP supplies to its retail operations, to third-party dealers and distributors, to independent operators of commission agent locations and other consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.
Sunoco LP is the exclusive wholesale supplier of the iconic Sunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,322 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest South Central and Southeast regions of the United States, including 245 company operated Sunoco-branded Stripes locations in Texas. Sunoco LP believes it is one of the largest independent motor fuel distributors by gallons in Texas and one of the largest distributors of Chevron, Exxon, Shell and Valero branded motor fuel in the United States. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.

Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distribute it across more than 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States, as well as Hawaii to approximately:
1,348 convenience stores and fuel outlets.
153 independently operated consignment locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;
5,501 convenience stores and retail fuel outlets operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution agreements; and
2,222 other commercial customers, including unbranded convenience stores, other fuel distributors, school districts and municipalities and other industrial customers.
On January 23, 2018, Sunoco LP sold a portfolio of 1,030 company-operated retail fuel outlets to 7-Eleven.
Retail Operations
As of December 31, 2017, prior to the closing of the amended and restated purchasing agreement with 7-Eleven, Sunoco LP’s retail segment operated approximately 1,348 convenience stores and retail fuel outlets. Sunoco LP’s retail convenience stores operates under several brands, including its proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. Sunoco LP has company operated sites in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.
As of December 31, 2017, Sunoco LP operated approximately 746 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on local customer demand and preferences. Sunoco LP built approximately 265 large-format convenience stores from January 2000 through December 31, 2017. Sunoco LP has implemented its proprietary, in-house Laredo Taco Company restaurant concept in approximately 477 Stripes convenience stores. Sunoco LP also owns and operates ATM and proprietary money order systems in most Stripes stores and provides other services such as lottery, prepaid telephone cards, wireless services and car washes.
As of December 31, 2017, Sunoco LP operated approximately 441 retail convenience stores and fuel outlets, primarily under its proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 404 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.
As of December 31, 2017, Sunoco LP operated approximately 161 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2017, MACS operated approximately 107 retail convenience stores and Aloha operated approximately 54 Aloha, Shell, and Mahalo branded fuel stations.
Investment in Lake Charles LNG
Lake Charles LNG provides terminal services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long term contracts with a wholly-owned subsidiary of BG Group plc (“BG”).
Lake Charles LNG is currently developing a natural gas liquefaction facility with BG for the export of LNG. In December 2015, Lake Charles LNG received authorization from the FERC to site, construct, and operate facilities for the liquefaction and export of natural gas. On February 15, 2016, Royal Dutch Shell plc completed its acquisition of BG. Shell announced in the second quarter of 2016 that they will delay making a final investment decision (“FID”) for the Lake Charles LNG project and Shell has not advised LCL of any change in the status of the project. In the event that each of LCL and Shell elect to make an affirmative FID, construction of the project would be expected to commence promptly thereafter and first LNG exports would commence about four years later.

Asset Overview
Investment in ETP
The descriptions below include summaries of significant assets within ETP’s operations. Amounts, such as capacities, volumes and miles included in the descriptions below are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.
The following details the assets in ETP’s operations:
Intrastate Transportation and Storage
The following details pipelines and storage facilities in ETP’s intrastate transportation and storage operations:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline Pipeline Throughput Capacity
(Bcf/d)		 Working Storage Capacity
(Bcf/d)
ET Fuel System 100% 2,780
 5.2
 11.2
Oasis Pipeline 100% 750
 2.3
 —
HPL System 100% 3,920
 5.3
 52.5
East Texas Pipeline 100% 460
 2.4
 —
RIGS Haynesville Partnership Co. 49.99% 450
 2.1
 —
Comanche Trail Pipeline 16% 195
 1.1
 —
Trans-Pecos Pipeline 16% 143
 1.4
 —
The following information describes ETP’s principal intrastate transportation and storage assets:
The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.
The ET Fuel System also includes the Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and the Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.
In addition, the ET Fuel System is integrated with ETP’s Godley processing plant which gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing its Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing ETP to bypass its processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas

in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing ETP to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, as well as ETP’s Bammel storage facility.
The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2017, ETP had approximately 10.8 Bcf committed under fee-based arrangements with third parties and approximately 36.9 Bcf stored in the facility for ETP’s own account.
The East Texas Pipeline connects three treating facilities, one of which ETP owns, with its Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect ETP’s Reed compressor station in Freestone County to its Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting ETP’s Cleburne to Carthage pipeline to the HPL System.
RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. The Partnership owns a 49.99% general partner interest in RIGS.
Comanche Trail is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.
Trans-Pecos is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.
Interstate Transportation and Storage
The following information describes ETP’s principal interstate transportation and storage assets:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline 
Pipeline Throughput Capacity
(Bcf/d)
 
Working Gas Capacity
(Bcf/d)
Florida Gas Transmission Pipeline 50% 5,360
 3.1
 —
Transwestern Pipeline 100% 2,570
 2.1
 —
Panhandle Eastern Pipe Line 100% 5,980
 2.8
 83.9
Trunkline Gas Pipeline 100% 2,220
 0.9
 13.0
Tiger Pipeline 100% 195
 2.4
 —
Fayetteville Express Pipeline 50% 185
 2.0
 —
Sea Robin Pipeline 100% 830
 2.0
 —
Rover Pipeline 32.6% 713
 3.25
 —
Midcontinent Express Pipeline 50% 500
 1.8
 —
Gulf States 100% 10
 0.1
 —
The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,360 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains over 81 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrials and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture between ETP and KMI.
The Transwestern Pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandles. Natural

gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
The Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan.
The Trunkline Gas Pipeline’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.
The Tiger Pipeline is an approximately 195-mile interstate natural gas pipeline with bi-directional capabilities, that connects to ETP’s dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.
The Fayetteville Express Pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.
The Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.
The Rover Pipeline is a new 713-mile natural gas pipeline designed to transport 3.25 Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market.
The Midcontinent Express Pipeline is an approximately 500-mile interstate pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline System in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI.
Gulf States owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
Midstream
The following details ETP’s assets in its midstream operations:
Description of Assets
Net Gas Processing Capacity
(MMcf/d)
 
Net Gas Treating Capacity
(MMcf/d)
South Texas Region:   
Southeast Texas System410
 510
Eagle Ford System1,920
 1,808
Ark-La-Tex Region1,025
 1,186
North Central Texas Region715
 212
Permian Region1,943
 1,580
Mid-Continent Region885
 20
Eastern Region—
 70
The following information describes ETP’s principal midstream assets:
South Texas Region:
The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plant (La Grange and Alamo) with aggregate capacity of 410 MMcf/d and natural gas treating facilities with aggregate capacity of 510 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process

the rich gas that flows through ETP’s gathering system to produce residue gas and NGLs. Residue gas is delivered into its intrastate pipelines and NGLs are delivered into ETP’s NGL pipelines to Lone Star.
ETP’s treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into ETP’s system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both ETP’s King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1,920 MMcf/d and multiple natural gas treating facilities with combined capacity of 1,808 MMcf/d. ETP’s Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to its intrastate transportation pipeline systems for deliveries of residue gas and are also connected with ETP’s NGL pipelines for delivery of NGLs to Lone Star.
Ark-La-Tex Region:
ETP’s Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including ETP’s Tiger Pipeline. ETP’s Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1,186 MMcf/d.
ETP’s PennTex Midstream System is primarily located in Lincoln Parish, Louisiana, and consists of the Lincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to ETP’s processing plants and third-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from ETP’s processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from ETP’s processing plants.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline. Collectively, the eight natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada and Brookeland) have an aggregate capacity of 1,025 MMcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, ETP offers producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. ETP’s North Central Texas assets include its Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 715 MMcf/d and aggregate treating capacity of 212 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of ETP’s system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that ETP gathers and processes, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes ten processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther and Rebel) with an aggregate processing capacity of 1,618 MMcf/d, treating capacity of 1,580 MMcf/d, and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.
ETP owns a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. ETP operates the plant and related facilities on behalf of Mi Vida JV.

ETP owns a 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.
Mid-Continent Region:
The Mid-Continent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. ETP’s Mid-Continent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Mid-Continent Systems include fourteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray and Gray) with an aggregate capacity of 885 MMcf/d and one natural gas treating facility with aggregate capacity of 20 MMcf/d.
ETP operates its Mid-Continent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
ETP also owns the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
Eastern Region:
The Eastern Region assets are located in nine counties in Pennsylvania, three counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. ETP’s Eastern Region assets include approximately 500 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems. The fresh water pipeline system and Ohio gathering assets are held by jointly-owned entities.
ETP also owns a 51% membership interest in Aqua – PVR, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
ETP and Traverse ORS LLC, a subsidiary of Traverse Midstream Partners LLC, own a 75% and 25% membership interest, respectively, in the ORS joint venture. On behalf of ORS, ETP operates ORS’s Ohio Utica River System (the “ORS System”), which consists of 47 miles of 36-inch and 13 miles of 30-inch gathering trunklines that delivers up to 2.1 Bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and others.

NGL and Refined Products Transportation and Services
The following details the assets in ETP’s NGL and refined products transportation and services operations:
Description of Assets
Miles of Liquids Pipeline (2)
 
Pipeline Throughput Capacity
(MBbls/d)
 
NGL Fractionation / Processing Capacity
(MBbls/d)
 
Working Storage Capacity
(MBbls)
Liquids Pipelines:       
Lone Star Express535
 507
 —
 —
West Texas Gateway Pipeline512
 240
 —
 —
Lone Star1,617
 120
 —
 —
Mariner East300
 70
    
Mariner South67
 200
    
Mariner West395
 50
    
Other NGL Pipelines645
 591
 —
 —
Liquids Fractionation and Services Facilities:       
Mont Belvieu Facilities163
 42
 520
 50,000
Sea Robin Processing Plant1
—
 —
 26
 —
Refinery Services1
103
 —
 25
 —
Hattiesburg Storage Facilities—
 —
 —
 3,000
NGLs Terminals:       
Nederland—
 —
 —
 1,000
Marcus Hook Industrial Complex—
 —
 90
 5,000
Inkster—
 —
 —
 1,000
Refined Products Pipelines2,200
 800
 —
 —
Refined Products Terminals:       
Eagle Point—
 —
 —
 6,000
Marcus Hook Industrial Complex—
 —
 —
 1,000
Marcus Hook Tank Farm—
 —
 —
 2,000
Marketing Terminals—
 —
 —
 8,000
(1)
Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of 850 MMcf/d and 54 MMcf/d, respectively.
(2)
Miles of pipeline as reported to PHMSA.
The following information describes ETP’s principal NGL and refined products transportation and services assets:
The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.
The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including ETP’s Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345 MBbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the second quarter of 2018.

The Mariner South pipeline is part of a joint project with Lone Star to deliver export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to ETP’s marine terminal in Nederland, Texas.
The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter of 2013, with capacity to transport approximately 50 MBbls/d.
Refined products pipelines include approximately 2,200 miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. These operations include ETP’s controlling financial interest in Inland Corporation (“Inland”). The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375 MBbls/d, the 45-mile Freedom pipeline with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140 MBbls/d.
ETP’s Mont Belvieu storage facility is an integrated liquids storage facility with over 50 million Bbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
ETP’s Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator V is currently under construction and is scheduled to be operational by the third quarter of 2018.
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.
Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana.  The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components.  The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 103 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 million Bbls of salt dome capacity, providing 100% fee-based cash flows.
The Nederland terminal, in addition to crude oil activities, also provides approximately 1 million Bbls of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be exported via ship.
The Marcus Hook Industrial Complex includes fractionation, terminalling and storage assets, with a capacity of approximately 2 million Bbls of NGL storage capacity in underground caverns, 3 million Bbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 million Bbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for the Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million Bbls of NGLs. ETP uses the Inkster terminal's storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
ETP has approximately 40 refined products terminals with an aggregate storage capacity of approximately 8 million Bbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million Bbls, and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million Bbls of refined products storage. The tank farm historically served Sunoco Inc.’s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.’s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on ETP’s refined products pipelines.
The Eastern refined products pipelines consists of approximately 470 miles of 6-inch to 24-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, approximately 162 miles of 8-inch refined products pipeline in western New York and approximately 182 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
The Mid-Continent refined products pipelines primarily consists of approximately 212 miles of 3-inch to 12-inch refined products pipelines in Ohio, approximately 85 miles of 6-inch to 12-inch refined products pipeline in Western Pennsylvania and approximately 52 miles of 8-inch refined products pipeline in Michigan.
The Southwest refined products pipelines is located in Eastern Texas and consists primarily of approximately 300 miles of 8-inch diameter refined products pipeline.
The Inland refined products pipeline, approximately 350 miles of pipeline in Ohio, consists of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 205 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 53 miles of 8-inch diameter refined products pipeline in western Ohio and the remaining refined products pipeline primarily consists of 5-inch diameter pipeline in Northeast Ohio.
Crude Oil Transportation and Services
The following details ETP’s pipelines and terminals in its crude oil transportation and services operations:
Description of Assets
Miles of Crude Pipeline (1)
Working Storage Capacity
(MBbls)
Dakota Access Pipeline1,172
—
Energy Transfer Crude Oil Pipeline743
—
Bayou Bridge Pipeline49
—
Permian Express Pipelines1,712
—
Other Crude Oil Pipelines5,682
—
Nederland Terminal—
26,000
Fort Mifflin Terminal—
570
Eagle Point Terminal—
1,000
Midland Terminal—
2,000
Marcus Hook Industrial Complex—
1,000
Patoka, Illinois Terminal—
2,000
(1)
Miles of pipeline as reported to PHMSA.
ETP’s crude oil operations consist of an integrated set of pipeline, terminalling, and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details ETP’s assets in its crude oil transportation and services operations:
Crude Oil Pipelines
ETP’s crude oil pipelines consist of approximately 9,358 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States, including ETP’s wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC (“PET”), and Mid-Valley Pipeline Company (“Mid-Valley”). Additionally, ETP has equity ownership interests in two crude oil pipelines.

ETP’s crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. ETP’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915 mile pipeline with an initial capacity of 470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including ETP’s crude terminal in Nederland Texas.
The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
Dakota Access went into service on June 1, 2017 and consists of approximately 1,172 miles of 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the ETCO Pipeline for delivery to the Gulf Coast, or can be transported via other pipelines to refining markets throughout the Midwest.
ETCO went into service on June 1, 2017 and consists of more than 743 miles consisting of 678 miles of mostly 30-inch converted natural gas pipeline and 65 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETP and Phillips 66, in which ETP has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.
When completed the Bayou Bridge Pipeline will have a capacity expandable to approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, which origins in multiple locations in Western Texas.
Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies its Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
Crude Oil Terminals
Nederland. The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 26 million Bbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland terminal can receive crude oil at four of its five ship docks and four barge berths. The four ship docks are capable of receiving over 2 million Bbls/d of crude oil. In addition to ETP’s crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United

States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million Bbls.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has two ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/d of crude oil to ETP’s crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin terminal complex by charging fees based on throughput.
The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.
The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of approximately 3 million Bbls. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via ETP’s pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via ETP’s pipelines.
Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1 million Bbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls of crude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.
Marcus Hook Industrial Complex. The Marcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 million Bbls.
Patoka, Illinois Terminal. The Patoka, Illinois terminal is a tank farm and was contributed by ExxonMobil to the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 2 million Bbls of crude oil storage.
Crude Oil Acquisition and Marketing
ETP’s crude oil acquisition and marketing operations are conducted using ETP’s assets, which include approximately 370 crude oil transport trucks and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets.
All Other
Equity Method Investments
Sunoco LP. ETP has an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, ETP’s investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, ETP’s investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

PES. ETP has a non-controlling interest in PES, comprising 33% of PES’ outstanding common units. As discussed in “ETP’s Other Operations and Investments” above, PES Holdings and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018.
Contract Services Operations
ETP owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. ETP’s contract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
ETP owns all of the outstanding equity interests of CDM, which operates a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas. As discussed in “Strategic Transactions,” in January 2018, ETP entered into an agreement to contribute CDM to USAC.
ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of ETT. ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’s other operations.
Natural Resources OperationsCrude Oil Pipelines
Regency is involvedETP’s crude oil pipelines consist of approximately 9,358 miles of crude oil trunk and gathering pipelines in the management of coalsouthwest and natural resources propertiesmidwest United States, including ETP’s wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC (“PET”), and Mid-Valley Pipeline Company (“Mid-Valley”). Additionally, ETP has equity ownership interests in two crude oil pipelines.

ETP’s crude oil pipelines provide access to several trading hubs, including the related collection of royalties. Regency also earns revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collectinglargest trading hub for crude oil and gas royalties. These operations also included Regency’s 50% interesting in Coal Handling, which owns and operates end-user coal handling facilities. Regency purchased the remaining 50% interest in Coal Handling effective December 31, 2014.
Investment in Lake Charles LNG
Lake Charles LNG provides terminal services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long term contracts with a wholly-owned subsidiary of BG Group plc (“BG”).
Lake Charles LNG is currently developing a planned liquefaction facility with BG for the export of LNG.
Asset Overview
Investment in ETP
The following details the assets in ETP’s operations:
Intrastate Transportation and Storage
The following details pipelines and storage facilities in ETP’s intrastate transportation and storage operations:
ET Fuel System
Capacity of 5.2 Bcf/d
Approximately 2,870 miles of natural gas pipeline
Two storage facilities with 12.4 Bcf of total working gas capacity
Bi-directional capabilities
The ET Fuel System serves some of the most prolific production areas in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. ETP’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is compriseda 1,915 mile pipeline with an initial capacity of intrastate470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including ETP’s crude terminal in Nederland Texas.
The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
Dakota Access went into service on June 1, 2017 and consists of approximately 1,172 miles of 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the ETCO Pipeline for delivery to the Gulf Coast, or can be transported via other pipelines to refining markets throughout the Midwest.
ETCO went into service on June 1, 2017 and consists of more than 743 miles consisting of 678 miles of mostly 30-inch converted natural gas pipeline and related natural gas65 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETP and Phillips 66, in which ETP has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.
When completed the Bayou Bridge Pipeline will have a capacity expandable to approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, which origins in multiple locations in Western Texas.
Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies its Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
Crude Oil Terminals
Nederland. The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage facilities.and distribution services for refiners and other large transporters of crude oil and NGLs. The ET Fuel Systemterminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has many interconnectionsa total storage capacity of approximately 26 million Bbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland terminal can receive crude oil at four of its five ship docks and four barge berths. The four ship docks are capable of receiving over 2 million Bbls/d of crude oil. In addition to ETP’s crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United

States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million Bbls.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has two ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/d of crude oil to ETP’s crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland terminal generates crude oil revenues primarily by providing directterm or spot storage services and throughput capabilities to a number of customers.
Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin terminal complex by charging fees based on throughput.
The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.
The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of approximately 3 million Bbls. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via ETP’s pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via ETP’s pipelines.
Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1 million Bbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to power plants, other intrastatevarious markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and interstate pipelinesstorage.
Midland. The Midland terminal is located in Midland, Texas and is strategically located near high-growth production areaswas acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls of crude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.Permian Express 2 transportation system.
The ET Fuel System also includes ETP’s Bethel natural gas storage facility, with a working capacity of 6.4 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and ETP’s Bryson natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. All of ETP’s storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2017.

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In addition, the ET Fuel System is integrated with ETP’s Godley processing plant which gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
Oasis Pipeline
Capacity of 1.2 Bcf/d
Approximately 600 miles of natural gas pipeline
Connects Waha to Katy market hubs
Bi-directional capabilities
The Oasis pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capability with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing ETP’s Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas on the Southeast Texas System to other third party supply and market points and interconnecting pipelines and (ii) allowing ETP to bypass ETP’s processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
HPL System
Capacity oMarcus Hook Industrial Complex. f 5.3 Bcf/d
Approximately 3,800 miles of natural gas pipeline
Bammel storage facility with 52.5 Bcf of total working gas capacity
The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing ETP to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, and ETP’s Bammel storage facility.
The Bammel storage facilityMarcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total working gasactive crude oil storage capacity of approximately 52.5 Bcf,1 million Bbls.
Patoka, Illinois Terminal. The Patoka, Illinois terminal is a peak withdrawal rate of 1.3 Bcf/dtank farm and a peak injection rate of 0.6 Bcf/d. The Bammel storage facilitywas contributed by ExxonMobil to the PEP joint venture and is located near the Houston Ship Channel market areain Marion County, Illinois. The facility includes 234 acres of owned land and the Katy Hubprovides for approximately 2 million Bbls of crude oil storage.
Crude Oil Acquisition and is ideally suited to provide a physical backup for on-systemMarketing
ETP’s crude oil acquisition and off-system customers. As of December 31, 2014, ETP hadmarketing operations are conducted using ETP’s assets, which include approximately 9.3 Bcf committed under fee-based arrangements with third parties370 crude oil transport trucks and approximately 40.2 Bcf stored in the facility for ETP’s own account.
East Texas Pipeline
Capacity of 2.4 Bcf/d
Approximately 370 miles of natural gas pipeline
The East Texas pipeline connects three treating150 crude oil truck unloading facilities, one of which ETP owns, with ETP’s Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provides access to the Katy Hub. The East Texas pipeline includes the 36-inch East Texas extension to connect ETP’s Reed compressor station in Freestone County to ETP’s Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting ETP’s Cleburne to Carthage pipeline to the HPL System.

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Interstate Transportation and Storage
The following details ETP’s pipelines in the interstate transportation and storage operations.
Florida Gas Transmission Pipeline
Capacity of 3.1 Bcf/d
Approximately 5,400 miles of interstate natural gas pipeline
FGT is owned by Citrus, a 50/50 joint venture with Kinder Morgan, Inc. (“KMI”)
The Florida Gas Transmission pipeline is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,400 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The Florida Gas Transmission pipeline system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 65% of the natural gas consumed in the state. In addition, Florida Gas Transmission’s pipeline system operates and maintains over 75 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions.
FGT’s customers include electric utilities, independent power producers, industrials and local distribution companies.
Transwestern Pipeline
Capacity of 2.1 Bcf/d
Approximately 2,600 miles of interstate natural gas pipeline
Bi-directional capabilities
The Transwestern pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern pipeline has access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle. Natural gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westwardthird-party truck, rail and marine assets.
All Other
Equity Method Investments
Sunoco LP. ETP has an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, ETP’s investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to markets in Arizona, Nevada and California. Transwestern’s Phoenix lateral pipeline, with a throughput capacitySunoco LP’s repurchase of 500 MMcf/d, connects the Phoenix area to the Transwestern mainline.
Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
Panhandle Eastern Pipe Line
Capacity of 2.8 Bcf/d
Approximately 6,000 miles of interstate natural gas pipeline
Bi-directional capabilities
The Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan. Panhandle Eastern Pipe Line is owned by a subsidiary of ETP Holdco.
Trunkline Gas Company
Capacity of 1.7 Bcf/d
Approximately 3,000 miles of interstate natural gas pipeline
Bi-directional capabilities
The Trunkline Gas pipeline’s transmission system consists of two large diameter pipelines extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and to Michigan. Trunkline Gas pipeline is owned by a subsidiary of ETP Holdco.
ETP is currently developing plans to convert a portion of the Trunkline gas pipeline to crude oil transportation.its common units on February 7, 2018, ETP’s investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

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Tiger Pipeline
Capacity of 2.4 Bcf/d
Approximately 195 miles of interstate natural gas pipeline
Bi-directional capabilities
The Tiger pipeline is an approximately 195-mile interstate natural gas pipeline that connects to ETP’s dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana. The pipelinePES. ETP has a capacitynon-controlling interest in PES, comprising 33% of 2.4 Bcf/d, allPES’ outstanding common units. As discussed in “ETP’s Other Operations and Investments” above, PES Holdings and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018.
Contract Services Operations
ETP owns and operates a fleet of which is sold under long-term contracts ranging from 10equipment used to 15 years.
Fayetteville Express Pipeline
Capacity of 2.0 Bcf/d
Approximately 185 miles of interstate natural gas pipeline
50/50 joint venture through ETC FEP with KMI
The Fayetteville Express pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The pipeline has long-term contracts for 1.85 Bcf/d ranging from 10 to 12 years.
Sea Robin Pipeline
Capacity of 2.3 Bcf/d
Approximately 1,000 miles of interstate natural gas pipeline
The Sea Robin pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.
Midstream
The following details the assets in ETP’s midstream operations:
Southeast Texas System
Approximately 6,400 miles of natural gas pipeline
One natural gas processing plant (La Grange) with aggregate capacity of 210 MMcf/d
11 natural gasprovide treating facilities with aggregate capacity of 1.4 Bcf/d
One natural gas conditioning facility with aggregate capacity of 200 MMcf/d
The Southeast Texas System is an integrated system that gathers, compresses, treats, processes and transports natural gas from the Austin Chalk trend. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas pipeline and is connected to the Oasis pipeline,services, such as well as two power plants. This allows ETP to bypass processing plants and treating facilities when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with natural gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The La Grange processing plant is a natural gas processing plant that processes the rich natural gas that flows through ETP’s system to produce residue gas and NGLs. Residue gas is delivered into ETP’s intrastate pipelines and NGLs are delivered into ETP’s NGL pipelines and then to Lone Star.
ETP’s treating facilities remove carbon dioxide and hydrogen sulfide fromremoval, natural gas gathered intocooling, dehydration and BTU management. ETP’s system beforecontract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
ETP owns all of the outstanding equity interests of CDM, which operates a natural gas is introducedcompression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas. As discussed in “Strategic Transactions,” in January 2018, ETP entered into an agreement to transportation pipelinescontribute CDM to ensure thatUSAC.
ETP owns 100% of the gas meets pipeline quality specifications. In addition, ETP’s conditioning facilities remove heavy hydrocarbons frommembership interests of ETG, which owns all of the gas gathered into ETP’s systems sopartnership interests of ETT. ETT provides compression services to customers engaged in the gas can be redelivered and meet downstream pipeline hydrocarbon dew point specifications.
North Texas System
Approximately 160 milestransportation of natural gas, pipeline
One natural gas processing plant (the Godley plant) with aggregate capacity of 700 MMcf/d
One natural gas conditioning facility with capacity of 100 MMcf/d

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The North Texas System is an integrated system located in four counties in North Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. The system includes ETP’s Godley processing plant, which processes rich natural gas produced from the Barnett Shale and is integrated with the North Texas System and the ET Fuel System. The facility consists of a processing plant and a conditioning facility.
Northern Louisiana
Approximately 280 miles of natural gas pipeline
Three natural gas treating facilities with aggregate capacity of 385 MMcf/d
ETP’s Northern Louisiana assets comprise several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including ETP’s Tiger pipeline. The Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems.other operations.
Eagle Ford System
Approximately 245 miles of natural gas pipeline
Three processing plants (Chisholm, Kenedy and Jackson) with capacity of 1,160 MMcf/d
One natural gas treating facility with capacity of 300 MMcf/d
The Eagle Ford gathering system consists of 30-inch and 42-inch natural gas transportation pipelines delivering 1.4 Bcf/d of capacity originating in Dimmitt County, Texas and extending to ETP’s Chisholm pipeline for ultimate deliveries to ETP’s existing processing plants. The Chisholm, Kenedy and Jackson processing plants are connected to ETP’s intrastate transportation pipeline systems for deliveries of residue gas and are also connected with ETP’s NGL pipelines for delivery of NGLs to Lone Star.
Other Midstream Assets
The midstream operations also include ETP’s interests in various midstream assets located in Texas, New Mexico and Louisiana, with approximately 60 miles of gathering pipelines aggregating a combined capacity of approximately 115 MMcf/d, as well as one conditioning facility and the recently commissioned Rebel processing plant with capacity of 130 MMcf/d. ETP also owns approximately 50 miles of gathering pipelines serving the Marcellus Shale in West Virginia with aggregate capacity of approximately 250 MMcf/d.
Liquids Transportation and Services
The following details ETP’s assets in the liquids transportation and services operations. Certain assets, as discussed below, are owned by Lone Star, a joint venture with Regency in which ETP has a 70% interest.
West Texas System
Capacity of 137,000 Bbls/d
Approximately 1,170 miles of NGL transmission pipelines
The West Texas System, owned by Lone Star, is an intrastate NGL pipeline consisting of 3-inch to 16-inch long-haul, mixed NGLs transportation pipeline that delivers 137,000 Bbls/d of capacity from processing plants in the Permian Basin and Barnett Shale to the Mont Belvieu NGL storage facility.
West Texas Gateway Pipeline
Capacity of 209,000 Bbls/d
Approximately 570 miles of NGL transmission pipeline
The West Texas Gateway Pipeline, owned by Lone Star, began service in December 2012 and transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.
Other NGL Pipelines
Aggregate capacity of 490,000 Bbls/d
Approximately 274 miles of NGL transmission pipelines
Other NGL pipelines include the 127-mile Justice pipeline with capacity of 340,000 Bbls/d, the 87-mile Liberty pipeline with a capacity of 90,000 Bbls/d, the 45-mile Freedom pipeline with a capacity of 40,000 Bbls/d and the 15-mile Spirit pipeline with a capacity of 20,000 Bbls/d.

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Rio Bravo Pipeline
Aggregate capacity of 100,000 Bbls/d
Approximately 83 miles of crude oil transmission pipeline
In 2014, ETP converted approximately 80 miles of natural gas pipeline from the HPL and Southeast Texas Systems to crude service and constructed approximately 3 miles of new crude oil pipeline.
Mont Belvieu Facilities
Working storage capacity of approximately 48 million Bbls
Approximately 185 miles of NGL transmission pipelines
300,000 Bbls/d NGL and propane fractionation facilities
The Mont Belvieu storage facility, owned by Lone Star, is an integrated liquids storage facility with over 48 million Bbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
The Lone Star Fractionators I and II, completed in December 2012 and October 2013, respectively, handle NGLs delivered from several sources, including Lone Star’s West Texas Gateway pipeline and the Justice pipeline.
Hattiesburg Storage Facility
Working storage capacity of approximately 4.5 million Bbls
The Hattiesburg storage facility, owned by Lone Star, is an integrated liquids storage facility with approximately 4.5 million Bbls of salt dome capacity, providing 100% fee-based cash flows.
Sea Robin Processing Plant
One processing plant with 850 MMcf/d residue capacity and 26,000 Bbls/d NGL capacity
20% non-operating interest held by Lone Star
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant, which is connected to nine interstate and four intrastate residue pipelines as well as various deep-water production fields, has a residue capacity of 850 MMcf/d and an NGL capacity of 26,000 Bbls/d.
Refinery Services
Two processing plants (Chalmette and Sorrento) with capacity of 54 MMcf/d
One NGL fractionator with 25,000 Bbls/d capacity
Approximately 100 miles of NGL pipelines
Refinery Services, owned by Lone Star, consists of a refinery off-gas processing and O-grade NGL fractionation complex located along the Mississippi River refinery corridor in southern Louisiana that cryogenically processes refinery off-gas and fractionates the O-grade NGL stream into its higher value components. The O-grade fractionator located in Geismar, Louisiana is connected by approximately 100 miles of pipeline to the Chalmette processing plant.
Investment in Sunoco Logistics
The following details the assets in ETP’s investment in Sunoco Logistics:
Crude Oil Pipelines
Sunoco Logistics’ETP’s crude oil pipelines consist of approximately 5,3009,358 miles of crude oil trunk pipelines for high-volume, long-distance transportation and approximately 500 miles of crude oil gathering pipelines in the southwest and midwest United States. These lines primarilyStates, including ETP’s wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC (“PET”), and Mid-Valley Pipeline Company (“Mid-Valley”). Additionally, ETP has equity ownership interests in two crude oil pipelines.

ETP’s crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. ETP’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
Bakken Pipeline. Dakota Access and other feedstocksETCO are collectively referred to refineries in those regions. Followingas the “Bakken Pipeline.” The Bakken Pipeline is a description1,915 mile pipeline with an initial capacity of Sunoco Logistics’470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude pipelines:oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including ETP’s crude terminal in Nederland Texas.
The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
Dakota Access went into service on June 1, 2017 and consists of approximately 1,172 miles of 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the ETCO Pipeline for delivery to the Gulf Coast, or can be transported via other pipelines to refining markets throughout the Midwest.
ETCO went into service on June 1, 2017 and consists of more than 743 miles consisting of 678 miles of mostly 30-inch converted natural gas pipeline and 65 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
Southwest United States:Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETP and Phillips 66, in which ETP has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.
When completed the Bayou Bridge Pipeline will have a capacity expandable to approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
Permian Express Pipelines. The Southwest United States pipeline system includes approximately 3,150 milesPermian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and approximately 300 miles of crude oil gathering pipelines in Texas. The Texas system includes the West Texas Gulf Pipe Line Company’s common carrier crude oil pipelines, which originateand Oklahoma and provide takeaway capacity from the West Texas oil fields at Colorado City, Texas and is connected toPermian Basin, which origins in multiple locations in Western Texas.
Other Crude Oil pipelines include the Mid-Valley pipeline other third-party pipelines and the Nederland Terminal. In December 2014, Sunoco Logistics acquired an additional 28.3% ownership interest in the West Texas Gulf Pipe Line Company from

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Chevron Pipe Line Company, increasing its controlling financial interest in the consolidated subsidiary to 88.6%. The remaining 11.4% was acquired from Southwest Pipeline Holding Company, LLC in January 2015.
The Southwest United States pipeline system also includes the Oklahoma crude oil pipeline and gathering system that consists of approximately 1,050 miles of crude oil trunk pipelines and approximately 200 miles of crude oil gathering pipelines. Sunoco Logistics has the ability to deliver substantially all of the crude oil gathered on the Oklahoma system to Cushing, Oklahoma and is one of the largest purchasers of crude oil from producers in the state.
Midwest United States: The Midwest United States pipeline system includes Sunoco Logistics’ majority interest in the Mid-Valley Pipeline Company and consists of approximately 1,000 miles of a crude oil pipeline thatwhich originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the midwestMidwest United States.
Sunoco Logistics also owns approximately 100 miles ofIn addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to Marathon’sMPLX’s Samaria, Michigan tank farm, which supplies its Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
Crude Oil AcquisitionWe also own and Marketing
Sunoco Logistics’operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and our crude oil acquisition and marketing activities includebusiness is the gathering, purchasing, marketing and selling ofprimary shipper on our Oklahoma crude oil primarily in the mid-continent United States. The operations are conducted using Sunoco Logistics’ assets, which include approximately 335 crude oil transport trucks and approximately 135 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets. Specifically, the crude oil acquisition and marketing activities include:system.
purchasing crude oil at the wellhead from producers, and in bulk from aggregators at major pipeline interconnections and trading locations;
storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);
buying and selling crude oil of different grades, at different locations in order to maximize value;
transporting crude oil on Sunoco Logistics’ pipelines and trucks or, when necessary or cost effective, pipelines or trucks owned and operated by third parties; and
marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
Terminal Facilities
Sunoco Logistics’ 39 active refined products terminals receive refined products from pipelines, barges, railcars, and trucks and distribute them to third parties and certain affiliates, who in turn deliver them to end-users and retail outlets.Crude Oil Terminals are facilities where products are transferred to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines.
Terminals play a key role in moving product to the end-user markets by providing the following services: storage; distribution; blending to achieve specified grades of gasoline and middle distillates; and other ancillary services that include the injection of additives and the filtering of jet fuel. Typically, Sunoco Logistics’ refined products terminal facilities consist of multiple storage tanks and are equipped with automated truck loading equipment that is operational 24 hours a day. This automated system provides controls over allocations, credit, and carrier certification.
Nederland Terminal:Nederland. The Nederland Terminal,terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 2526 million barrelsBbls in approximately 130150 above ground storage tanks with individual capacities of up to 660,000 barrels.660 MBbls.
The Nederland Terminalterminal can receive crude oil at eachfour of its five ship docks and threefour barge berths. The fivefour ship docks are capable of receiving over 2 million Bbls/d of crude oil. In addition to Sunoco Logistics’ETP’s crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United

States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 400approximately 395 million barrels.Bbls.

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The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has two ship rail, or truck.docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/d of crude oil to Sunoco Logistics’ETP’s crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland Terminal can also receive NGLs in connection with the Mariner South pipeline.terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
Fort Mifflin Terminal Complex:Mifflin. The Fort Mifflin Terminal Complexterminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin Terminal,terminal, the Hog Island Wharf,wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin Terminal Complexterminal complex by charging fees based on throughput.
The Fort Mifflin Terminalterminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570,000 barrels.570 MBbls. Crude oil and some refined products enter the Fort Mifflin Terminalterminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class (“VLCC”) tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island Wharfwharf is located next to the Fort Mifflin Terminalterminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.
The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES.PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of approximately 3 million barrels. Bbls. Darby Creek receives crude oil from the Fort Mifflin Terminalterminal and Hog Island Wharfwharf via Sunoco LogisticsETP’s pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via Sunoco LogisticsETP’s pipelines.
Marcus Hook Industrial Complex: In 2013, Sunoco Logistics acquired Sunoco, Inc.’s Marcus Hook Industrial Complex. The acquisition included terminalling and storage assets with a capacity of approximately 3 million barrels located in Pennsylvania and Delaware, including approximately 2 million barrels of NGL storage capacity in underground caverns, and related commercial agreements. The facility can receive NGLs via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex also provides customers with the use of industrial space and equipment at the facility, as well as logistical, utility and infrastructure services.
Eagle Point Terminal:Point. The Eagle Point Terminalterminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 61 million barrelsBbls and can receive crude oil and refined products via barge pipeline and rail. The terminal canrail and deliver via ship and barge, truck, rail or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage for clean products and dark oils.storage.
Inkster Terminal:Midland. The Inkster Terminal,Midland terminal is located near Detroit, Michigan, consistsin Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls of eight salt caverns withcrude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.
Marcus Hook Industrial Complex. The Marcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 975,000 barrels. The Inkster Terminal’s storage is used in connection with the Toledo, Ohio to Sarnia, Canada pipeline system and for the storage of NGLs from local producers and a refinery in western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and offloading rack.

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The following table outlines the number of Sunoco Logistics’ active terminals and storage capacity by state:
State Number of Terminals Storage Capacity (thousands of Bbls)
Indiana 1
 206
Louisiana 1
 161
Maryland 1
 710
Massachusetts 1
 1,144
Michigan 3
 760
New Jersey 3
 650
New York(1)
 4
 920
Ohio 7
 957
Pennsylvania 13
 1,743
Texas 4
 548
Virginia 1
 403
Total 39
 8,202
(1)
Sunoco Logistics has a 45% ownership interest in a terminal at Inwood, New York and a 50% ownership interest in a terminal at Syracuse, New York. The storage capacities included in the table represent the proportionate share of capacity attributable to Sunoco Logistics’ ownership interests in these terminals.
Products Pipelines
Sunoco Logistics owns and operates approximately 2,400 miles of products pipelines in several regions of the United States. The products pipelines primarily transport refined products and NGLs from refineries in the northeast, midwest and southwest United States to markets in New York, New Jersey, Pennsylvania, Ohio, Michigan and Texas. These pipelines include approximately 350 miles of products pipelines owned by Sunoco Logistics’ consolidated joint venture, Inland Corporation (“Inland”).
The refined products transported in these pipelines include multiple grades of gasoline, middle distillates (such as heating oil, diesel and jet fuel), and LPGs (such as propane and butane). In addition, certain of these pipelines transport NGLs from processing and fractionation areas to marketing and distribution facilities. Rates for shipments on the products pipelines are regulated by the FERC and the Pennsylvania Public Utility Commission (“PA PUC”), among other state regulatory agencies.
Mariner East: Mariner East 1 and Mariner East 2 are pipeline projects to deliver NGLs from the Marcellus and Utica Shale areas in western Pennsylvania, West Virginia and eastern Ohio to the Marcus Hook Industrial Complex on the Delaware River in Pennsylvania, where it will be processed, stored and distributed to various local, domestic and waterborne markets. Mariner East 2 is the second phase of the project, which will expand the total take-away capacity to 345,000 Bbls/d. Mariner East 1 commenced initial operations in the fourth quarter of 2014 and Mariner East 2 is expected to commence operations in the fourth quarter 2016.million Bbls.
Mariner Souther:Patoka, Illinois Terminal. The Mariner South pipeline provides transportation of propanePatoka, Illinois terminal is a tank farm and butane products from the Mont Belvieu, Texas areawas contributed by ExxonMobil to the Nederland Terminal, where such products can be sold by wayPEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of ship. Mariner South commenced initial operations in December 2014, with an initial capacityowned land and provides for approximately 2 million Bbls of 200,000 Bbls/d of NGLs and other products.crude oil storage.
Inland: Inland is Sunoco Logistics’ 83.8% owned joint venture consisting of approximately 350 miles of active products pipelines in Ohio. The pipeline connects three refineries in Ohio to terminalsCrude Oil Acquisition and major markets within the state. As Sunoco Logistics owns a controlling financial interest in Inland, the joint venture is reflected as a consolidated subsidiary in its consolidated financial statements.

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Sunoco Logistics owns equity interests in several common carrier products pipelines, summarized in the following table:
Pipeline Equity Ownership Pipeline Mileage
Explorer Pipeline Company(1)
 13.3% 1,850
Yellowstone Pipe Line Company(2)
 14.0% 700
West Shore Pipe Line Company(3)
 17.1% 650
Wolverine Pipe Line Company(4)
 31.5% 700
(1)
The system, which is operated by Explorer employees, originates from the refining centers of Beaumont, Port Arthur and Houston, Texas, and extends to Chicago, Illinois, with delivery points in the Houston, Dallas/Fort Worth, Tulsa, St. Louis, and Chicago areas. Explorer charges market-based rates for all its tariffs. An additional 3.9% ownership interest was purchased in the first quarter of 2014.
(2)
The system, which is operated by Phillips 66, originates from the Billings, Montana refining center and extends to Moses Lake, Washington with delivery points along the way. Tariff rates are regulated by the FERC for interstate shipments and the Montana Public Service Commission for intrastate shipments in Montana.
(3)
The system, which is operated by Buckeye Partners, L.P., originates from the Chicago, Illinois refining center and extends to Madison and Green Bay, Wisconsin with delivery points along the way. West Shore charges market-based tariff rates in the Chicago area.
(4)
The system, which is operated by Wolverine employees, originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan with delivery points along the way. Wolverine charges market-based rates for tariffs at the Detroit, Jackson, Niles, Hammond, and Lockport destinations.
Retail Marketing
ETP’s retailcrude oil acquisition and marketing operations are conducted using ETP’s assets, which include approximately 370 crude oil transport trucks and wholesale distribution operations consist of the retail sale of motor fuel and merchandise through company-operated locations, and the distribution of branded and unbranded motor fuel purchased primarily from refiners to company-operated retail sites, independently-operated retail sites,approximately 150 crude oil truck unloading facilities, as well as other wholesalethird-party truck, rail and commercial customers.marine assets.
The business is operated through various wholly-owned subsidiaries as well as through Sunoco LP which ETP controls through its ownership of the general partner. ETP currently plans to contribute all of the retail operations and fuel distributions business to Sunoco LP in future periods. In October 2014, ETP completed the first of such transactions, when one of ETP’s subsidiaries contributed all of the ownership of MACS to All Other
Equity Method Investments
Sunoco LP.
The retail marketing operations have a portfolio ETP has an equity method investment in limited partnership units of outlets operating under three channels of trade: company-operated, dealer-operated and distributor-operated sites. The portfolio of sites in these channels differ in various ways including: site ownership and operation, product distribution to the outlets, and types/brands of products and services provided.
Company-operated sites, which are operated by one of our subsidiaries, and independent dealer-operated sites are sites at which fuel products are delivered directly to the site by company-operated trucks or by contract carriers. One of our subsidiaries may own or lease the property and collect rental income or an independent dealer owns or leases the property. Independent dealers are supplied under a contract with one of our subsidiaries. Most of the company-operated sites include a convenience store under the Aplus®, Stripes®, MACS, Tigermarket or Aloha Island Mart® brands.Sunoco LP. As of December 31, 2014, our subsidiaries were operating or supplying under a long-term contract a2017, ETP’s investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total of 75 Sunoco®-branded outlets on turnpikes and expressways in Pennsylvania, New Jersey, New York, Maryland, Ohio and Delaware.
Distributor outlets are primarily Sunoco®-branded sites in which the distributor takes delivery of fuel products at a terminal where branded products are available. ETP subsidiaries supply the distributor under a long-term contract, but do not own, lease or operate these distributor locations.
The highest concentration of retail outlets are located in Texas, Pennsylvania, New York, Florida and Ohio.

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The following table sets forth ETP’s retail gasoline outlets at December 31, 2014 (including sites operated through its subsidiaries):
Retail and Fuel Distribution Outlets:Sunoco LP Wholly-Owned Subsidiaries Total
Company-Owned or Leased:    
Company-Operated(1)
155
 1,096
 1,251
Dealer-Operated138
 425
 563
Total293
 1,521
 1,814
Dealer Owned655
 541
 1,196
Distributor Outlets—
 3,640
 3,640
Total948
 5,702
 6,650
(1)
Gasoline and diesel throughput per company-operated site averaged 177,236 gallons per month during 2014.
Brands
ETP manages a portfolio of strong proprietary fuel and convenience store brands through its retail and wholesale portfolio of outlets, including Sunoco®, Stripes®, Aplus®, and Aloha Island Mart®.
Of the total retail outlets that are company-operated or operating under a long-term contract by an independent third-party, 4,961 operate under the Sunoco® fuel brand as of December 31, 2014. The Sunoco® brand is positioned as a premium fuel brand. Brand improvements in recent years have focused on physical image, customer service and product offerings. In addition,outstanding common units. Subsequent to Sunoco Inc. believes its brands and high performance gasoline business have benefited from its sponsorship agreements with NASCAR®, INDYCAR® and the NHRA®. Under the sponsorship agreement with NASCAR®, which continues until 2022, Sunoco® is the Official Fuel of NASCAR® and APlus® is the Official Convenience Store of NASCAR®. Sunoco, Inc. has exclusive rights to use certain NASCAR® trademarks to advertise and promote Sunoco, Inc. products and is the exclusive fuel supplier for the three major NASCAR® racing series. The sponsorship agreements with INDYCAR® and NHRA® continue through 2018 and 2024, respectively.
In addition to operating premium proprietary brands, our subsidiaries operate as a significant distributor to multiple top-tier fuel brands, including Exxon®, Mobil®, Valero®, Shell® and Chevron®.
Convenience Store and Restaurant Operations
ETP subsidiaries operate 1,185 convenience stores primarily under our proprietary Stripes®, Aplus® and Aloha Island Mart® convenience store brands as of December 31, 2014. These stores complement sales of fuel products with a broad mix of merchandise, food service, and other services. As of December 31, 2014, 474 of these stores featured in-store restaurants allowing us to make fresh food on the premises daily. Laredo Taco Company® is ETP’s in-house proprietary restaurant operation featuring breakfast and lunch tacos, a wide variety of handmade authentic Mexican food and other hot food offerings targeted to local populations in the markets served. Some of these stores also offer other proprietary and third party food options, including Subway® sandwiches and Godfather® pizza.
The following table sets forth information concerning the company-operated convenience stores during 2014:
Number of stores at December 31, 2014 1,185
Merchandise sales (thousands of dollars/store/month) $127
Merchandise margin (% sales) 31.4%
ETP’s retail marketing operations also include the distribution of gasoline, distillate and other petroleum products to wholesalers, unbranded retailers and other commercial customers.

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Investment in Regency
The following details the assets in Regency’s natural gas operations:
Gathering and Processing Operations
Arklatex Region
Four cryogenic natural gas processing facilities, two refrigeration plants, a conditioning plant and two amine treating plants
Compression horsepower of 96,834
Regency’s Arklatex assets gather, compress, treat and dehydrate natural gas in several Parishes of north and west Louisiana and several counties in east Texas. Its assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, Regency offers producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
In May 2014, Regency announced the constructionLP’s repurchase of a new 200 MMcf/d cryogenic processing plant and 47-mile, 40,000 bbls/d capacity NGL pipeline, forportion of its common units on February 7, 2018, ETP’s investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

PES. ETP has a combined total of $191 million, which is expected to be completed in mid-2015.
South Texas Region
Three treating plants
Compression horsepower of 187,723
Regency’s south Texas assets gather, compress, treat and dehydrate natural gas in Bee, LaSalle, Webb, Karnes, Atascosa, McMullen, Frio and Dimmitt counties. Some of the natural gas produced in this region can have significant quantities of hydrogen sulfide and carbon dioxide that require treating to remove these impurities. The pipeline systems that gather this gas are connected to third-party processing plants and Regency’s treating facilities that include an acid gas reinjection wells located in McMullen County, Texas. Regency also gathers oil for producers in the region and delivers it to tanks for further transportation by truck or pipeline.
The natural gas supply for Regency’s south Texas gathering systems is derived from a combination of natural gas wells located in a mature basin that generally have long lives and predictable gas flow rates, including the Frio, Vicksburg, Miocene, Canyon Sands and Wilcox formations, and the NGLs-rich and oil-rich Eagle Ford shale formation, which lies directly under Regency’s existing south Texas gathering system infrastructure.
Regency owns a 60%non-controlling interest in Edwards Lime Gathering LLC with Talisman Energy USA Inc.PES, comprising 33% of PES’ outstanding common units. As discussed in “ETP’s Other Operations and Statoil Texas Onshore Properties LP owning the remaining 40% interest. Regency operates a natural gas gathering oil pipelineInvestments” above, PES Holdings and oil stabilization facilitieseight affiliates filed for the joint venture while its joint venture partners operate a lean gas gathering system in the Edwards Lime natural gas trend that delivers to this system.
Permian Region
Six processing and treating plants, two processing plants and two treating plants
Compression horsepower of 387,932
Regency’s Permian Basin gathering system assets offer wellhead-to-market services to producers in the Texas counties of Ward, Winkler, Reeves, Pecos, Crocket, Upton, Crane, Ector, Culberson, Reagan and Andrews counties, as well as into Eddy and Lea counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGLs-rich natural gas market areas. As a result of the proximity of Regency’s system to the Waha Hub, the Waha gathering system has a variety of market outlets for the natural gas that Regency gathers and processes, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets include Lone Star’s NGL pipeline.
Regency’s Permian region assets consist of a network of natural gas and NGL pipelines, six processing and treating plants, two processing plants, and two treating plants. These assets offer a broad array of services to producers including field gathering and compression of natural gas; treating, dehydration, sulfur recovery and reinjection and other conditioning; and natural gas processing and marketing of natural gas and NGLs.
In October 2014, Regency entered into a joint venture with Anadarko Mi Vida LLC (“Anadarko”). Anadarko and Regency each own a 50% membership interest in the new joint venture, Mi Vida JV. Regency will construct and operate a 200 MMcf/d cryogenic processing plant and related facilities in west Texas,Chapter 11 bankruptcy protection on behalf of Mi Vida JV.January 21, 2018.

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Regency owns a 33.33% membership interest in Ranch JV which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 100 MMcf/d cryogenic processing plant.
Mid-Continent Region
14 processing facilities
Compression horsepower of 425,394
Regency’s mid-continent systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. Regency’s mid-continent gathering assets are extensive systems that gather, compress and dehydrate low-pressure gas. Regency has 14 natural gas producing facilities and approximately 12,995 miles of gathering pipeline.
Regency operates its mid-continent gathering systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
Regency also owns the Hugoton gathering system that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
Eastern Region
Compression horsepower of 112,282
Regency’s eastern region assets are located in Pennsylvania, Ohio, and West Virginia, and gather natural gas from the Marcellus and Utica basins. Regency’s eastern gathering assets include approximately 370 miles of natural gas gathering pipeline, natural gas trunkline pipelines, and fresh water pipelines, and the Lycoming, Wyoming, East Lycoming, Bradford, Green County, and Preston gathering and processing systems. Regency’s Eastern operations earn revenues primarily from fees charged to producers for natural gas gathering, transportation, compression and other related services.
Regency also own a 51% membership interest in Aqua - PVR Water Services, LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
In August 2014, Regency entered into a joint venture with American Energy - Midstream, LLC (“AEM”). Regency and AEM own a 75% and 25% membership interest, respectively, in the new joint venture Ohio River System LLC (“ORS”). On behalf of ORS, Regency is constructing and will operate its Ohio Utica River System, (the “ORS System”) which consists of a 52-mile, 36-inch gathering trunkline that will be capable of delivering up to 2.1 bcf/d to Rockies Express Pipeline (“REX”) and Texas Eastern Transmission, and potentially others and the construction of 25,000 horsepower of compression at the REX interconnect. This project will also include the construction of a 12-mile, 30-inch lateral that will initially connect to the tailgate of the Cadiz processing plant and Harrison County wellhead production. The system is expected to be completed in the third quarter of 2015. Total costs for the ORS System are expected to be approximately $500 million; 75% contributed from Regency and 25% contributed from AEM. Additionally, Regency and American Energy - Utica, LLC (“AEU”), an affiliate of AEM, entered into a gathering agreement for gas produced from the Utica Shale in eastern Ohio by AEU.
Natural Gas Transportation Operations
RIGS has the capacity to transport up to 2.1 Bcf/d of natural gas. Results of RIGS’s operations are determined primarily by the volumes of natural gas transported and subscribed on its intrastate pipeline system and the level of fees charged to customers or the margins received from purchases and sales of natural gas. RIGS generates revenues and margins principally under fee-based transportation contracts. The fixed capacity reservation charges related to RIGS that are not directly dependent on throughput volumes or commodity prices represent 93% of HPC’s margin.
MEP pipeline system, operated by KMI, has the capability to transport up to 1.8 Bcf/d of natural gas, and the pipeline capacity is nearly fully subscribed, Zone 1 is 95% subscribed and Zone 2 is fully subscribed, with long-term binding commitments from creditworthy shippers. Results of MEP’s operations are determined primarily by the volumes of natural gas transported and subscribed on its interstate pipeline system and the level of fees charged to customers. MEP generates revenues and margins principally under fee-based transportation contracts. The margin MEP earns is primarily related to fixed capacity reservation charges that are not directly dependent on throughput volumes or commodity prices. If a sustained decline in commodity prices should result in a decline in volumes, MEP’s revenues would not be significantly impacted until expiration of the current contracts.

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Gulf States is a small interstate pipeline that uses cost-based rates and terms and conditions of service for shippers wishing to secure capacity for interstate transportation service. Rates charged are largely governed by long-term negotiated rate agreements.
NGL Services Operations
Regency owns a 30% membership interest in Lone Star. ETP owns the remaining 70% membership interest. See “Liquids Transportation and Services” under ETP’s asset overview discussion for additional details.
Contract Services Operations
Regency’s contract services operations include contract compression services and contract treating services. The natural gas contract compression services include designing, sourcing, owning, installing, operating, servicing, repairing and maintaining compressors and related equipment for which Regency guarantees their customers 98% mechanical availability for land installations and 96% mechanical availability for over-water installations. Regency focuses on meeting the complex requirements of field-wide compression applications, as opposed to targeting the compression needs of individual wells within a field. These field-wide applications include compression for natural gas gathering and natural gas processing. Regency believes that it improves the stability of its cash flow by focusing on field-wide compression applications because such applications generally involve long-term installations of multiple large horsepower compression units. Regency’s contract compression operations are located in Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico, Colorado and California.
RegencyETP owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. Regency’sETP’s contract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
ETP owns all of the outstanding equity interests of CDM, which operates a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas. As discussed in “Strategic Transactions,” in January 2018, ETP entered into an agreement to contribute CDM to USAC.
ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of ETT. ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’s other operations.
Natural Resources OperationsInvestment in Lake Charles LNG
Regency’s Natural Resources operations primarily involveLake Charles LNG provides terminal services for shippers by receiving LNG at the managementfacility for storage and leasingdelivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of coal propertiesits revenue from a series of long term contracts with a wholly-owned subsidiary of BG Group plc (“BG”).
Lake Charles LNG is currently developing a natural gas liquefaction facility with BG for the export of LNG. In December 2015, Lake Charles LNG received authorization from the FERC to site, construct, and operate facilities for the liquefaction and export of natural gas. On February 15, 2016, Royal Dutch Shell plc completed its acquisition of BG. Shell announced in the second quarter of 2016 that they will delay making a final investment decision (“FID”) for the Lake Charles LNG project and Shell has not advised LCL of any change in the status of the project. In the event that each of LCL and Shell elect to make an affirmative FID, construction of the project would be expected to commence promptly thereafter and first LNG exports would commence about four years later.

Asset Overview
Investment in ETP
The descriptions below include summaries of significant assets within ETP’s operations. Amounts, such as capacities, volumes and miles included in the descriptions below are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.
The following details the assets in ETP’s operations:
Intrastate Transportation and Storage
The following details pipelines and storage facilities in ETP’s intrastate transportation and storage operations:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline Pipeline Throughput Capacity
(Bcf/d)		 Working Storage Capacity
(Bcf/d)
ET Fuel System 100% 2,780
 5.2
 11.2
Oasis Pipeline 100% 750
 2.3
 —
HPL System 100% 3,920
 5.3
 52.5
East Texas Pipeline 100% 460
 2.4
 —
RIGS Haynesville Partnership Co. 49.99% 450
 2.1
 —
Comanche Trail Pipeline 16% 195
 1.1
 —
Trans-Pecos Pipeline 16% 143
 1.4
 —
The following information describes ETP’s principal intrastate transportation and storage assets:
The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the subsequent collectionCarthage Hub in East Texas, the three major natural gas trading centers in Texas.
The ET Fuel System also includes the Bethel natural gas storage facility, with a working capacity of royalties. Regency6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and the Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.
In addition, the ET Fuel System is integrated with ETP’s Godley processing plant which gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing its Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing ETP to bypass its processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas

in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing ETP to play an important role in the Texas natural gas markets. The HPL System also earn revenues fromoffers its shippers off-system opportunities due to its numerous interconnections with other land management activities, suchpipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, as selling standing timber, leasing fee-based coalrelated infrastructure facilitieswell as ETP’s Bammel storage facility.
The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to certain lesseesprovide a physical backup for on-system and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees.off-system customers. As of December 31, 2014, Regency2017, ETP had approximately 10.8 Bcf committed under fee-based arrangements with third parties and approximately 36.9 Bcf stored in the facility for ETP’s own account.
The East Texas Pipeline connects three treating facilities, one of which ETP owns, with its Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect ETP’s Reed compressor station in Freestone County to its Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting ETP’s Cleburne to Carthage pipeline to the HPL System.
RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. The Partnership owns a 49.99% general partner interest in RIGS.
Comanche Trail is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.
Trans-Pecos is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.
Interstate Transportation and Storage
The following information describes ETP’s principal interstate transportation and storage assets:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline 
Pipeline Throughput Capacity
(Bcf/d)
 
Working Gas Capacity
(Bcf/d)
Florida Gas Transmission Pipeline 50% 5,360
 3.1
 —
Transwestern Pipeline 100% 2,570
 2.1
 —
Panhandle Eastern Pipe Line 100% 5,980
 2.8
 83.9
Trunkline Gas Pipeline 100% 2,220
 0.9
 13.0
Tiger Pipeline 100% 195
 2.4
 —
Fayetteville Express Pipeline 50% 185
 2.0
 —
Sea Robin Pipeline 100% 830
 2.0
 —
Rover Pipeline 32.6% 713
 3.25
 —
Midcontinent Express Pipeline 50% 500
 1.8
 —
Gulf States 100% 10
 0.1
 —
The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,360 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains over 81 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrials and local distribution companies. FGT is owned or controlled approximately 821 million tonsby Citrus, a 50/50 joint venture between ETP and KMI.
The Transwestern Pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of provenWest Texas, eastern and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, Tennessee, southwestern Virginianorthwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: the Permian Basin in West Virginia;Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandles. Natural

gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
The Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Basin, properties in southernIndiana, Ohio and into Michigan.
The Trunkline Gas Pipeline’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.
The Tiger Pipeline is an approximately 195-mile interstate natural gas pipeline with bi-directional capabilities, that connects to ETP’s dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.
The Fayetteville Express Pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.
The Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.
The Rover Pipeline is a new 713-mile natural gas pipeline designed to transport 3.25 Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market.
The Midcontinent Express Pipeline is an approximately 500-mile interstate pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline System in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI.
Gulf States owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
Midstream
The following details ETP’s assets in its midstream operations:
Description of Assets
Net Gas Processing Capacity
(MMcf/d)
 
Net Gas Treating Capacity
(MMcf/d)
South Texas Region:   
Southeast Texas System410
 510
Eagle Ford System1,920
 1,808
Ark-La-Tex Region1,025
 1,186
North Central Texas Region715
 212
Permian Region1,943
 1,580
Mid-Continent Region885
 20
Eastern Region—
 70
The following information describes ETP’s principal midstream assets:
South Texas Region:
The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plant (La Grange and Alamo) with aggregate capacity of 410 MMcf/d and natural gas treating facilities with aggregate capacity of 510 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process

the rich gas that flows through ETP’s gathering system to produce residue gas and NGLs. Residue gas is delivered into its intrastate pipelines and NGLs are delivered into ETP’s NGL pipelines to Lone Star.
ETP’s treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into ETP’s system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both ETP’s King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1,920 MMcf/d and multiple natural gas treating facilities with combined capacity of 1,808 MMcf/d. ETP’s Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to its intrastate transportation pipeline systems for deliveries of residue gas and are also connected with ETP’s NGL pipelines for delivery of NGLs to Lone Star.
Ark-La-Tex Region:
ETP’s Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including ETP’s Tiger Pipeline. ETP’s Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1,186 MMcf/d.
ETP’s PennTex Midstream System is primarily located in Lincoln Parish, Louisiana, and consists of the Lincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to ETP’s processing plants and third-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from ETP’s processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from ETP’s processing plants.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline. Collectively, the eight natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada and Brookeland) have an aggregate capacity of 1,025 MMcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, ETP offers producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. ETP’s North Central Texas assets include its Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 715 MMcf/d and aggregate treating capacity of 212 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of ETP’s system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that ETP gathers and processes, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes ten processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther and Rebel) with an aggregate processing capacity of 1,618 MMcf/d, treating capacity of 1,580 MMcf/d, and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.
ETP owns a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. ETP operates the plant and related facilities on behalf of Mi Vida JV.

ETP owns a 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.
Mid-Continent Region:
The Mid-Continent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western KentuckyOklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. ETP’s Mid-Continent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Mid-Continent Systems include fourteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray and Gray) with an aggregate capacity of 885 MMcf/d and one natural gas treating facility with aggregate capacity of 20 MMcf/d.
ETP operates its Mid-Continent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
ETP also owns the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
Eastern Region:
The Eastern Region assets are located in nine counties in Pennsylvania, three counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. ETP’s Eastern Region assets include approximately 500 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems. The fresh water pipeline system and Ohio gathering assets are held by jointly-owned entities.
ETP also owns a 51% membership interest in Aqua – PVR, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
ETP and Traverse ORS LLC, a subsidiary of Traverse Midstream Partners LLC, own a 75% and 25% membership interest, respectively, in the ORS joint venture. On behalf of ORS, ETP operates ORS’s Ohio Utica River System (the “ORS System”), which consists of 47 miles of 36-inch and 13 miles of 30-inch gathering trunklines that delivers up to 2.1 Bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and others.

NGL and Refined Products Transportation and Services
The following details the assets in ETP’s NGL and refined products transportation and services operations:
Description of Assets
Miles of Liquids Pipeline (2)
 
Pipeline Throughput Capacity
(MBbls/d)
 
NGL Fractionation / Processing Capacity
(MBbls/d)
 
Working Storage Capacity
(MBbls)
Liquids Pipelines:       
Lone Star Express535
 507
 —
 —
West Texas Gateway Pipeline512
 240
 —
 —
Lone Star1,617
 120
 —
 —
Mariner East300
 70
    
Mariner South67
 200
    
Mariner West395
 50
    
Other NGL Pipelines645
 591
 —
 —
Liquids Fractionation and Services Facilities:       
Mont Belvieu Facilities163
 42
 520
 50,000
Sea Robin Processing Plant1
—
 —
 26
 —
Refinery Services1
103
 —
 25
 —
Hattiesburg Storage Facilities—
 —
 —
 3,000
NGLs Terminals:       
Nederland—
 —
 —
 1,000
Marcus Hook Industrial Complex—
 —
 90
 5,000
Inkster—
 —
 —
 1,000
Refined Products Pipelines2,200
 800
 —
 —
Refined Products Terminals:       
Eagle Point—
 —
 —
 6,000
Marcus Hook Industrial Complex—
 —
 —
 1,000
Marcus Hook Tank Farm—
 —
 —
 2,000
Marketing Terminals—
 —
 —
 8,000
(1)
Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of 850 MMcf/d and 54 MMcf/d, respectively.
(2)
Miles of pipeline as reported to PHMSA.
The following information describes ETP’s principal NGL and refined products transportation and services assets:
The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.
The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including ETP’s Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345 MBbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the second quarter of 2018.

The Mariner South pipeline is part of a joint project with Lone Star to deliver export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to ETP’s marine terminal in Nederland, Texas.
The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter of 2013, with capacity to transport approximately 50 MBbls/d.
Refined products pipelines include approximately 2,200 miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. These operations include ETP’s controlling financial interest in Inland Corporation (“Inland”). The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375 MBbls/d, the 45-mile Freedom pipeline with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140 MBbls/d.
ETP’s Mont Belvieu storage facility is an integrated liquids storage facility with over 50 million Bbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
ETP’s Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator V is currently under construction and is scheduled to be operational by the third quarter of 2018.
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.
Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana.  The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components.  The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 103 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 million Bbls of salt dome capacity, providing 100% fee-based cash flows.
The Nederland terminal, in addition to crude oil activities, also provides approximately 1 million Bbls of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be exported via ship.
The Marcus Hook Industrial Complex includes fractionation, terminalling and storage assets, with a capacity of approximately 2 million Bbls of NGL storage capacity in underground caverns, 3 million Bbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 million Bbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for the Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million Bbls of NGLs. ETP uses the Inkster terminal's storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
ETP has approximately 40 refined products terminals with an aggregate storage capacity of approximately 8 million Bbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million Bbls, and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million Bbls of refined products storage. The tank farm historically served Sunoco Inc.’s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.’s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on ETP’s refined products pipelines.
The Eastern refined products pipelines consists of approximately 470 miles of 6-inch to 24-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, approximately 162 miles of 8-inch refined products pipeline in western New York and approximately 182 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
The Mid-Continent refined products pipelines primarily consists of approximately 212 miles of 3-inch to 12-inch refined products pipelines in Ohio, approximately 85 miles of 6-inch to 12-inch refined products pipeline in Western Pennsylvania and approximately 52 miles of 8-inch refined products pipeline in Michigan.
The Southwest refined products pipelines is located in Eastern Texas and consists primarily of approximately 300 miles of 8-inch diameter refined products pipeline.
The Inland refined products pipeline, approximately 350 miles of pipeline in Ohio, consists of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 205 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 53 miles of 8-inch diameter refined products pipeline in western Ohio and the remaining refined products pipeline primarily consists of 5-inch diameter pipeline in Northeast Ohio.
Crude Oil Transportation and Services
The following details ETP’s pipelines and terminals in its crude oil transportation and services operations:
Description of Assets
Miles of Crude Pipeline (1)
Working Storage Capacity
(MBbls)
Dakota Access Pipeline1,172
—
Energy Transfer Crude Oil Pipeline743
—
Bayou Bridge Pipeline49
—
Permian Express Pipelines1,712
—
Other Crude Oil Pipelines5,682
—
Nederland Terminal—
26,000
Fort Mifflin Terminal—
570
Eagle Point Terminal—
1,000
Midland Terminal—
2,000
Marcus Hook Industrial Complex—
1,000
Patoka, Illinois Terminal—
2,000
(1)
Miles of pipeline as reported to PHMSA.
ETP’s crude oil operations consist of an integrated set of pipeline, terminalling, and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details ETP’s assets in its crude oil transportation and services operations:
Crude Oil Pipelines
ETP’s crude oil pipelines consist of approximately 9,358 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States, including ETP’s wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC (“PET”), and Mid-Valley Pipeline Company (“Mid-Valley”). Additionally, ETP has equity ownership interests in two crude oil pipelines.

ETP’s crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. ETP’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915 mile pipeline with an initial capacity of 470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including ETP’s crude terminal in Nederland Texas.
The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
Dakota Access went into service on June 1, 2017 and consists of approximately 1,172 miles of 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the ETCO Pipeline for delivery to the Gulf Coast, or can be transported via other pipelines to refining markets throughout the Midwest.
ETCO went into service on June 1, 2017 and consists of more than 743 miles consisting of 678 miles of mostly 30-inch converted natural gas pipeline and 65 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETP and Phillips 66, in which ETP has a 60% ownership interest and serves as the operator of end-user coal handling facilities. Since 2004, the Natural Resources segment heldpipeline. Phase I of the pipeline, which consists of a 50% interest30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.
When completed the Bayou Bridge Pipeline will have a coal services company with Alpha Natural Resources. In December 2014, we acquiredcapacity expandable to approximately 480 MBbls/d of light and heavy crude oil from different sources to the remaining 50% membership interest. The company, now know as Materials Handling Solutions, LLC, owns and operates facilities for industrial customers on a fee basis. During 2014, our coal reservesSt. James crude oil hub, which is home to important refineries located in the San Juan basin depletedGulf Coast region.
Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, which origins in multiple locations in Western Texas.
Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies its Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and our associated coal royaltiescrude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
Crude Oil Terminals
Nederland. The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 26 million Bbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland terminal can receive crude oil at four of its five ship docks and four barge berths. The four ship docks are capable of receiving over 2 million Bbls/d of crude oil. In addition to ETP’s crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United

States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million Bbls.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has two ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/d of crude oil to ETP’s crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland terminal generates crude oil revenues ceased.primarily by providing term or spot storage services and throughput capabilities to a number of customers.
Coal reserves
Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are coal tons that can be economically extracted or produced at the time of determination considering legal, economic and technical limitations. All of the estimates of Regency’s coal reserves are classified as proven and probable reserves. Proven and probable coal reserves are defined as follows:
Proven Coal Reserves. Proven coal reserves are reserves for which: (i) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; (ii) grade and/or quality are computedgenerated from the resultsFort Mifflin terminal complex by charging fees based on throughput.
The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of detailed sampling;approximately 570 MBbls. Crude oil and (iii)some refined products enter the sites for inspection, samplingFort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and measurement are spaced so closely,smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the geologic character is so well defined, that the size, shape, depth and mineral contentother of reserves are well-established.
Probable Coal Reserves. Probable coal reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are more widely spaced or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven coal reserves, is high enough to assume continuity between points of observation.
In areas where geologic conditions indicate potential inconsistencies related to coal reserves, Regency performs additional exploration to ensure the continuity and mineability of the coal reserves. Consequently, sampling in those areas involves drill holes or channel samples that are spaced closer together than those distances cited above.
Coal reserve estimates are adjusted annually for production, unmineable areas, acquisitions and sales of coal in place. The majority of Regency’s coal reserves are high in energy content, low in sulfur and suitable for either the steam or to a lesser extent the metallurgical market.can accommodate some smaller crude oil vessels.
The amountDarby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of coal thatapproximately 3 million Bbls. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via ETP’s pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via ETP’s pipelines.
Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a lesseetank farm. The docks are located on the Delaware River and can profitably mine at any given time is subjectaccommodate three marine vessels (ships or barges) to several factorsreceive and may be substantially different from “provendeliver crude oil, intermediate products and probable coal reserves.” Included among the factors that influence profitability are the existing market price, coal qualityrefined products to outbound ships and operating costs.

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Tablebarges. The tank farm has a total active storage capacity of Contents

Regency enters into long-term leasesapproximately 1 million Bbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with experienced, third-party mine operators, providing them the rightaccess to mine coal reserves in exchange for royalty payments. Regency actively works with its lessees to develop efficient methods to exploit its reserves and to maximize production from its properties. Regency does not operate any mines. In 2014, Regency’s lessees produced 15.9 million tons of coal (11.3 million tons from March 21, 2014 (the date of acquisition) to December 31, 2014) from Regency’s properties and paid coal royalty revenues of $59 million ($44 million from March 21, 2014 (the date of acquisition) to December 31, 2014). Approximately 84% of Regency’s coal royalty revenues in 2014 were derived from coal mined on properties under leases containing royalty ratesvarious markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls of crude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the higherPermian Express 2 transportation system.
Marcus Hook Industrial Complex. The Marcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 million Bbls.
Patoka, Illinois Terminal. The Patoka, Illinois terminal is a fixed base price or a percentagetank farm and was contributed by ExxonMobil to the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of the gross sales price. The balanceowned land and provides for approximately 2 million Bbls of Regency’s coal royalty revenues for the respective periods was derived from coal mined on properties under leases containing fixed royalty rates that escalate annually.crude oil storage.
Regency’s lessees mine coalCrude Oil Acquisition and Marketing
ETP’s crude oil acquisition and marketing operations are conducted using both undergroundETP’s assets, which include approximately 370 crude oil transport trucks and surface methods.approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets.
All Other
Equity Method Investments
Sunoco LP. ETP has an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2014, Regency’s lessees operated 24 surface mines2017, ETP’s investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, ETP’s investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

PES. ETP has a non-controlling interest in PES, comprising 33% of PES’ outstanding common units. As discussed in “ETP’s Other Operations and 24 underground mines. Approximately 57%Investments” above, PES Holdings and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018.
Contract Services Operations
ETP owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. ETP’s contract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
ETP owns all of the coal produced from our propertiesoutstanding equity interests of CDM, which operates a natural gas compression equipment business with operations in 2014 came from underground minesArkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and 43% came from surface mines. MostTexas. As discussed in “Strategic Transactions,” in January 2018, ETP entered into an agreement to contribute CDM to USAC.
ETP owns 100% of Regency’s lessees use the continuous mining method in their underground mines located on its properties. In continuous mining, main airways and transportation entries are developed and remote-controlled continuous miners extract coal from “entries,” leaving “pillars”membership interests of ETG, which owns all of the partnership interests of ETT. ETT provides compression services to support the roof. Shuttle cars transport coal to a conveyor belt for transportation to the surface. In several underground mines, Regency’s lessees use two continuous miners running at the same time, also known as a supersection, to improve productivity and reduce unit costs.
The following tables set forth production data for the periods presented and reserve information with respect to each of Regency’s properties for the period presented (tons in millions):
 Production for the Years Ended December 31,
Property2014 2013
Central Appalachia9.0
 10.2
Northern Appalachia2.7
 3.3
Illinois Basin2.4
 2.4
San Juan Basin (1)
1.8
 9.2
     Total15.9
 25.1
(1) Regency’s San Juan reserves were fully depletedcustomers engaged in the first quartertransportation of 2014.

The following table sets forth the coal reserves Regency owned and leased with respect to each of its coal properties as of December 31, 2014 (tons in millions):
PropertyOwned Leased Total Controlled
Central Appalachia482.3
  141.0
  623.3
Northern Appalachia16.6
  —
  16.6
Illinois Basin150.5
  30.7
  181.2
    Total649.4
  171.7
  821.1
The following table sets forth Regency’s coal reserve activity for the periods presented and ended (tons in millions):
 2014 2013
Reserves - beginning of year847.0
 871.0
     Purchase of coal reserves—
 2.3
     Tons mined by lessees(15.9) (25.1)
     Revisions of estimates and other(10.0) (1.2)
Reserves - end of year821.1
 847.0
Regency’s coal reserve estimates are prepared from geological data assembled and analyzed by our general partner’s or its affiliates’ geologists and engineers. These estimates are compiled using geological data taken from thousands of drill holes, geophysical logs, adjacent mine workings, outcrop prospect openings andnatural gas, including ETP’s other sources. These estimates also take into account legal, qualitative, technical and economic limitations that may keep coal from being mined. Coal reserve estimates will change from time to time due to mining activities, analysis of new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods and other factors.operations.

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Table of Contents

Investment in Lake Charles LNG
Lake Charles LNG provides terminal services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long term contracts with a wholly-owned subsidiary of BG Group plc (“BG”).
Lake Charles LNG is currently developing a natural gas liquefaction facility with BG for the export of LNG. In December 2015, Lake Charles LNG received authorization from the FERC to site, construct, and operate facilities for the liquefaction and export of natural gas. On February 15, 2016, Royal Dutch Shell plc completed its acquisition of BG. Shell announced in the second quarter of 2016 that they will delay making a final investment decision (“FID”) for the Lake Charles LNG project and Shell has not advised LCL of any change in the status of the project. In the event that each of LCL and Shell elect to make an affirmative FID, construction of the project would be expected to commence promptly thereafter and first LNG exports would commence about four years later.

Asset Overview
Investment in ETP
The descriptions below include summaries of significant assets within ETP’s operations. Amounts, such as capacities, volumes and miles included in the descriptions below are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.
The following details the assets in ETP’s operations:
Intrastate Transportation and Storage
The following details pipelines and storage facilities in ETP’s intrastate transportation and storage operations:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline Pipeline Throughput Capacity
(Bcf/d)		 Working Storage Capacity
(Bcf/d)
ET Fuel System 100% 2,780
 5.2
 11.2
Oasis Pipeline 100% 750
 2.3
 —
HPL System 100% 3,920
 5.3
 52.5
East Texas Pipeline 100% 460
 2.4
 —
RIGS Haynesville Partnership Co. 49.99% 450
 2.1
 —
Comanche Trail Pipeline 16% 195
 1.1
 —
Trans-Pecos Pipeline 16% 143
 1.4
 —
The following information describes ETP’s principal intrastate transportation and storage assets:
The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.
The ET Fuel System also includes the Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and the Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.
In addition, the ET Fuel System is integrated with ETP’s Godley processing plant which gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing its Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing ETP to bypass its processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas

in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing ETP to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, as well as ETP’s Bammel storage facility.
The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2017, ETP had approximately 10.8 Bcf committed under fee-based arrangements with third parties and approximately 36.9 Bcf stored in the facility for ETP’s own account.
The East Texas Pipeline connects three treating facilities, one of which ETP owns, with its Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect ETP’s Reed compressor station in Freestone County to its Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting ETP’s Cleburne to Carthage pipeline to the HPL System.
RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. The Partnership owns a 49.99% general partner interest in RIGS.
Comanche Trail is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.
Trans-Pecos is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.
Interstate Transportation and Storage
The following information describes ETP’s principal interstate transportation and storage assets:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline 
Pipeline Throughput Capacity
(Bcf/d)
 
Working Gas Capacity
(Bcf/d)
Florida Gas Transmission Pipeline 50% 5,360
 3.1
 —
Transwestern Pipeline 100% 2,570
 2.1
 —
Panhandle Eastern Pipe Line 100% 5,980
 2.8
 83.9
Trunkline Gas Pipeline 100% 2,220
 0.9
 13.0
Tiger Pipeline 100% 195
 2.4
 —
Fayetteville Express Pipeline 50% 185
 2.0
 —
Sea Robin Pipeline 100% 830
 2.0
 —
Rover Pipeline 32.6% 713
 3.25
 —
Midcontinent Express Pipeline 50% 500
 1.8
 —
Gulf States 100% 10
 0.1
 —
The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,360 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains over 81 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrials and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture between ETP and KMI.
The Transwestern Pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandles. Natural

gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
The Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan.
The Trunkline Gas Pipeline’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.
The Tiger Pipeline is an approximately 195-mile interstate natural gas pipeline with bi-directional capabilities, that connects to ETP’s dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.
The Fayetteville Express Pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.
The Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.
The Rover Pipeline is a new 713-mile natural gas pipeline designed to transport 3.25 Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market.
The Midcontinent Express Pipeline is an approximately 500-mile interstate pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline System in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI.
Gulf States owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
Midstream
The following details ETP’s assets in its midstream operations:
Description of Assets
Net Gas Processing Capacity
(MMcf/d)
 
Net Gas Treating Capacity
(MMcf/d)
South Texas Region:   
Southeast Texas System410
 510
Eagle Ford System1,920
 1,808
Ark-La-Tex Region1,025
 1,186
North Central Texas Region715
 212
Permian Region1,943
 1,580
Mid-Continent Region885
 20
Eastern Region—
 70
The following information describes ETP’s principal midstream assets:
South Texas Region:
The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plant (La Grange and Alamo) with aggregate capacity of 410 MMcf/d and natural gas treating facilities with aggregate capacity of 510 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process

the rich gas that flows through ETP’s gathering system to produce residue gas and NGLs. Residue gas is delivered into its intrastate pipelines and NGLs are delivered into ETP’s NGL pipelines to Lone Star.
ETP’s treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into ETP’s system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both ETP’s King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1,920 MMcf/d and multiple natural gas treating facilities with combined capacity of 1,808 MMcf/d. ETP’s Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to its intrastate transportation pipeline systems for deliveries of residue gas and are also connected with ETP’s NGL pipelines for delivery of NGLs to Lone Star.
Ark-La-Tex Region:
ETP’s Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including ETP’s Tiger Pipeline. ETP’s Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1,186 MMcf/d.
ETP’s PennTex Midstream System is primarily located in Lincoln Parish, Louisiana, and consists of the Lincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to ETP’s processing plants and third-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from ETP’s processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from ETP’s processing plants.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline. Collectively, the eight natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada and Brookeland) have an aggregate capacity of 1,025 MMcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, ETP offers producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. ETP’s North Central Texas assets include its Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 715 MMcf/d and aggregate treating capacity of 212 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of ETP’s system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that ETP gathers and processes, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes ten processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther and Rebel) with an aggregate processing capacity of 1,618 MMcf/d, treating capacity of 1,580 MMcf/d, and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.
ETP owns a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. ETP operates the plant and related facilities on behalf of Mi Vida JV.

ETP owns a 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.
Mid-Continent Region:
The Mid-Continent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. ETP’s Mid-Continent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Mid-Continent Systems include fourteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray and Gray) with an aggregate capacity of 885 MMcf/d and one natural gas treating facility with aggregate capacity of 20 MMcf/d.
ETP operates its Mid-Continent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
ETP also owns the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
Eastern Region:
The Eastern Region assets are located in nine counties in Pennsylvania, three counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. ETP’s Eastern Region assets include approximately 500 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems. The fresh water pipeline system and Ohio gathering assets are held by jointly-owned entities.
ETP also owns a 51% membership interest in Aqua – PVR, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
ETP and Traverse ORS LLC, a subsidiary of Traverse Midstream Partners LLC, own a 75% and 25% membership interest, respectively, in the ORS joint venture. On behalf of ORS, ETP operates ORS’s Ohio Utica River System (the “ORS System”), which consists of 47 miles of 36-inch and 13 miles of 30-inch gathering trunklines that delivers up to 2.1 Bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and others.

NGL and Refined Products Transportation and Services
The following details the assets in ETP’s NGL and refined products transportation and services operations:
Description of Assets
Miles of Liquids Pipeline (2)
 
Pipeline Throughput Capacity
(MBbls/d)
 
NGL Fractionation / Processing Capacity
(MBbls/d)
 
Working Storage Capacity
(MBbls)
Liquids Pipelines:       
Lone Star Express535
 507
 —
 —
West Texas Gateway Pipeline512
 240
 —
 —
Lone Star1,617
 120
 —
 —
Mariner East300
 70
    
Mariner South67
 200
    
Mariner West395
 50
    
Other NGL Pipelines645
 591
 —
 —
Liquids Fractionation and Services Facilities:       
Mont Belvieu Facilities163
 42
 520
 50,000
Sea Robin Processing Plant1
—
 —
 26
 —
Refinery Services1
103
 —
 25
 —
Hattiesburg Storage Facilities—
 —
 —
 3,000
NGLs Terminals:       
Nederland—
 —
 —
 1,000
Marcus Hook Industrial Complex—
 —
 90
 5,000
Inkster—
 —
 —
 1,000
Refined Products Pipelines2,200
 800
 —
 —
Refined Products Terminals:       
Eagle Point—
 —
 —
 6,000
Marcus Hook Industrial Complex—
 —
 —
 1,000
Marcus Hook Tank Farm—
 —
 —
 2,000
Marketing Terminals—
 —
 —
 8,000
(1)
Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of 850 MMcf/d and 54 MMcf/d, respectively.
(2)
Miles of pipeline as reported to PHMSA.
The following information describes ETP’s principal NGL and refined products transportation and services assets:
The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.
The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including ETP’s Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345 MBbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the second quarter of 2018.

The Mariner South pipeline is part of a joint project with Lone Star to deliver export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to ETP’s marine terminal in Nederland, Texas.
The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter of 2013, with capacity to transport approximately 50 MBbls/d.
Refined products pipelines include approximately 2,200 miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. These operations include ETP’s controlling financial interest in Inland Corporation (“Inland”). The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375 MBbls/d, the 45-mile Freedom pipeline with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140 MBbls/d.
ETP’s Mont Belvieu storage facility is an integrated liquids storage facility with over 50 million Bbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
ETP’s Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator V is currently under construction and is scheduled to be operational by the third quarter of 2018.
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.
Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana.  The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components.  The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 103 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 million Bbls of salt dome capacity, providing 100% fee-based cash flows.
The Nederland terminal, in addition to crude oil activities, also provides approximately 1 million Bbls of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be exported via ship.
The Marcus Hook Industrial Complex includes fractionation, terminalling and storage assets, with a capacity of approximately 2 million Bbls of NGL storage capacity in underground caverns, 3 million Bbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 million Bbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for the Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million Bbls of NGLs. ETP uses the Inkster terminal's storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
ETP has approximately 40 refined products terminals with an aggregate storage capacity of approximately 8 million Bbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million Bbls, and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million Bbls of refined products storage. The tank farm historically served Sunoco Inc.’s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.’s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on ETP’s refined products pipelines.
The Eastern refined products pipelines consists of approximately 470 miles of 6-inch to 24-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, approximately 162 miles of 8-inch refined products pipeline in western New York and approximately 182 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
The Mid-Continent refined products pipelines primarily consists of approximately 212 miles of 3-inch to 12-inch refined products pipelines in Ohio, approximately 85 miles of 6-inch to 12-inch refined products pipeline in Western Pennsylvania and approximately 52 miles of 8-inch refined products pipeline in Michigan.
The Southwest refined products pipelines is located in Eastern Texas and consists primarily of approximately 300 miles of 8-inch diameter refined products pipeline.
The Inland refined products pipeline, approximately 350 miles of pipeline in Ohio, consists of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 205 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 53 miles of 8-inch diameter refined products pipeline in western Ohio and the remaining refined products pipeline primarily consists of 5-inch diameter pipeline in Northeast Ohio.
Crude Oil Transportation and Services
The following details ETP’s pipelines and terminals in its crude oil transportation and services operations:
Description of Assets
Miles of Crude Pipeline (1)
Working Storage Capacity
(MBbls)
Dakota Access Pipeline1,172
—
Energy Transfer Crude Oil Pipeline743
—
Bayou Bridge Pipeline49
—
Permian Express Pipelines1,712
—
Other Crude Oil Pipelines5,682
—
Nederland Terminal—
26,000
Fort Mifflin Terminal—
570
Eagle Point Terminal—
1,000
Midland Terminal—
2,000
Marcus Hook Industrial Complex—
1,000
Patoka, Illinois Terminal—
2,000
(1)
Miles of pipeline as reported to PHMSA.
ETP’s crude oil operations consist of an integrated set of pipeline, terminalling, and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details ETP’s assets in its crude oil transportation and services operations:
Crude Oil Pipelines
ETP’s crude oil pipelines consist of approximately 9,358 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States, including ETP’s wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC (“PET”), and Mid-Valley Pipeline Company (“Mid-Valley”). Additionally, ETP has equity ownership interests in two crude oil pipelines.

ETP’s crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. ETP’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915 mile pipeline with an initial capacity of 470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including ETP’s crude terminal in Nederland Texas.
The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
Dakota Access went into service on June 1, 2017 and consists of approximately 1,172 miles of 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the ETCO Pipeline for delivery to the Gulf Coast, or can be transported via other pipelines to refining markets throughout the Midwest.
ETCO went into service on June 1, 2017 and consists of more than 743 miles consisting of 678 miles of mostly 30-inch converted natural gas pipeline and 65 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETP and Phillips 66, in which ETP has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.
When completed the Bayou Bridge Pipeline will have a capacity expandable to approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, which origins in multiple locations in Western Texas.
Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies its Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
Crude Oil Terminals
Nederland. The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 26 million Bbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland terminal can receive crude oil at four of its five ship docks and four barge berths. The four ship docks are capable of receiving over 2 million Bbls/d of crude oil. In addition to ETP’s crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United

States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million Bbls.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has two ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/d of crude oil to ETP’s crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin terminal complex by charging fees based on throughput.
The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.
The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of approximately 3 million Bbls. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via ETP’s pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via ETP’s pipelines.
Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1 million Bbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls of crude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.
Marcus Hook Industrial Complex. The Marcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 million Bbls.
Patoka, Illinois Terminal. The Patoka, Illinois terminal is a tank farm and was contributed by ExxonMobil to the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 2 million Bbls of crude oil storage.
Crude Oil Acquisition and Marketing
ETP’s crude oil acquisition and marketing operations are conducted using ETP’s assets, which include approximately 370 crude oil transport trucks and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets.
All Other
Equity Method Investments
Sunoco LP. ETP has an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, ETP’s investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, ETP’s investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

PES. ETP has a non-controlling interest in PES, comprising 33% of PES’ outstanding common units. As discussed in “ETP’s Other Operations and Investments” above, PES Holdings and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018.
Contract Services Operations
ETP owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. ETP’s contract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
ETP owns all of the outstanding equity interests of CDM, which operates a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas. As discussed in “Strategic Transactions,” in January 2018, ETP entered into an agreement to contribute CDM to USAC.
ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of ETT. ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’s other operations.
Natural Resources Operations
ETP’s Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. ETP also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2017, ETP owned or controlled approximately 766 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.
Liquefaction Project
LCL, an entity whose parent is owned 60% by ETE and 40% by ETP, is in the process of developing a liquefaction project at the site of ETE’s existing regasification facility in Lake Charles, Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc (now "Shell") related to this project expired in February 2017. On June 28, 2017, LCL signed a memorandum of understanding with Korea Gas Corporation and Shell to study the feasibility of a joint development of the Lake Charles liquefaction project. The project would utilize existing dock and storage facilities owned by ETE located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia).  Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.
The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of exporting and importing LNG. Shell is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project would be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL. In March 2013, LCL obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”). The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively.

ETP has received its wetlands permits from the United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.
Investment in Sunoco LP
The following details the assets of Sunoco LP:
Wholesale Subsidiaries
Sunoco LLC, a Delaware limited liability company, primarily distributes motor fuel across 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama and the Greater Dallas, Texas metroplex.
Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands.
Retail Subsidiaries
Susser Petroleum Property Company LLC, a Delaware limited liability company, primarily owns and leases convenience store properties.
Susser, a Delaware corporation, sells motor fuel and merchandise in Texas, New Mexico, and Oklahoma through Stripes-branded convenience stores.
Sunoco Retail, a Pennsylvania limited liability company, owns and operates convenience stores that sell motor fuel and merchandise primarily in Pennsylvania, New York, and Florida.
MACS Retail LLC, a Virginia limited liability company, owns and operates convenience stores in Virginia, Maryland, and Tennessee.
Aloha Petroleum, Ltd., a Hawaii corporation, owns and operates convenience stores on the Hawaiian Islands.
As of December 31, 2017, prior to the closing of the amended and restated purchasing agreement with 7-Eleven, Sunoco LP’s retail segment operated approximately 1,348 convenience stores and retail fuel outlets. Sunoco LP’s retail convenience stores operates under several brands, including its proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. Sunoco LP has company operated sites in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.
As of December 31, 2017, Sunoco LP operated approximately 746 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on local customer demand and preferences. Sunoco LP built approximately 265 large-format convenience stores from January 2000 through December 31, 2017. Sunoco LP has implemented its proprietary, in-house Laredo Taco Company restaurant concept in approximately 477 Stripes convenience stores. Sunoco LP also owns and operates ATM and proprietary money order systems in most Stripes stores and provides other services such as lottery, prepaid telephone cards, wireless services and car washes.
As of December 31, 2017, Sunoco LP operated approximately 441 retail convenience stores and fuel outlets, primarily under its proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 404 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.
As of December 31, 2017, Sunoco LP operated approximately 161 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2017, MACS operated approximately 107 retail convenience stores and Aloha operated approximately 54 Aloha, Shell, and Mahalo branded fuel stations.
Investment in Lake Charles LNG
Regasification Facility
Lake Charles LNG, a wholly-owned subsidiary of ETE, owns a LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a run rate send out capacity of 1.8 bcf/Bcf/day.

Liquefaction Project
LCL, an entity owned 60% by ETE and 40% by ETP, is in the process of developing the liquefaction project in conjunction with BG pursuant to a project development agreement entered into in September 2013.2013 and scheduled to expire at the end of February 2017, subject to the parties’ right to mutually extend the term. Pursuant to this agreement, each of LCL and BG are obligated to pay 50% of the development expenses for the liquefaction project, subject to reimbursement by the other party if such party withdraws from the project prior to both parties making an affirmative FID to become irrevocably obligated to fully develop the project, subject to certain exceptions. The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.216.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility will become a bi-directional facility capable of exporting and importing LNG. BG is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project willis expected to be constructed on 400440 acres of land, of which 20080 acres are owned or leased by Lake Charles LNG and 200the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District or purchased by LCL pursuant to the exercise of an option agreement entered into in connection with the liquefaction project.District.
The constructionliquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project is subjectwill enable LCL to each of LCLliquefy domestically produced natural gas and BG making an affirmative FID to proceed withexport it as LNG. By adding the project, which decision is in the sole discretion of each party. In the event an affirmative FID is made by both parties, LCL and BG will enter into several agreements related to the project, including a liquefaction services agreement pursuant to which BG will pay LCL for liquefaction services on a tolling basis for a minimum 25-year term with evergreen extension options for 20 years. In addition, a subsidiary of BG, a highly experienced owner and operator of LNG facilities, would oversee construction of thenew liquefaction facility and upon completionintegrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of construction, manageexporting and importing LNG. Shell is the operationssole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the liquefaction facility on behalfregasification capacity regardless of LCL. Subjectwhether it actually utilizes such capacity pursuant to receipt of regulatory approvals, we anticipatea regasification services agreement that each of LCL and BG will make an affirmative FIDterminates in 2016 and then commence construction of the2030. The liquefaction project in order to place the firstwould be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG train in service in late 2019 and the secondremaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and third trains in service during 2020.Terminal District.
The export of LNG produced by the liquefaction project from the U.S. willUnited States would be undertaken under long-term export authorizations issued by the DOE to Lake Charles Exports, LLC (“LCE”), which is currently a jointly owned subsidiary of BG and ETP and following FID, will be 100% owned by BG.LCL. In July 2011, LCEMarch 2013, LCL obtained a DOE authorization to export LNG to countries with which the U.S.United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”).  In August 2013, LCEJuly 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”).  The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively. 
In January 2013, LCL filed for a secondary, non-cumulative FTA and Non-FTA Authorization to be held by LCL. FTA Authorization was granted in March 2013 and we expect the DOE to issue the Non-FTA Authorization to LCL in due course.
Prior to being authorized to export LNG, we must also receive (i) approvals from the FERC to construct and operate the facilities, (ii)addition, We have received our wetlands permits from the U.S.United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities, and (iii) air permits from the Louisiana Department of Environmental Quality (“LDEQ”) for emissions from the liquefaction project. We expect to receive the wetlands permit from the USACE and the air permit from the LDEQ in the third quarter of 2015.
In January 2015, LCL received from FERC its notice of schedule. The FERC notice of schedule provides an important timeline for the issuance of the Notice of Availability of Final Environmental Impact Statement (the “FEIS”). The issuance of the FEIS is scheduled for August 14, 2015, which then starts the 90-day period in which other federal agencies are to complete their review of the project and issue any required agency authorizations. The federal decision deadline date is November 12, 2015 and the FERC authorization for the project is anticipated during this 90-day period.facilities.
Competition
Natural Gas

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The business of providing natural gas gathering, compression, treating, transporting, storing and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage operations are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.
We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.
In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

NGL
In markets served by our NGL pipelines, we face competition with other pipeline companies, including those affiliated with major oil, petrochemical and natural gas companies, and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service. We face competition with other storage facilities based on fees charged and the ability to receive and distribute the customer’s products. We compete with a number of NGL fractionators in Texas and Louisiana. Competition for such services is primarily based on the fractionation fee charged.
Crude Oil and Products
In markets served by our products and crude oil pipelines, we face competition withfrom other pipelines.pipelines as well as rail and truck transportation. Generally, pipelines are the lowest cost method for long-haul, overland movement of products and crudcrude oil. Therefore, the most significant competitors for large volume shipments in the areas served by our pipelines are other pipelines. In addition, pipeline operations face competition from rail and trucks that deliver products in a number of areas that our pipeline operations serve. While their costs may not be competitive for longer hauls or large volume shipments, rail and trucks compete effectively for incremental and marginal volume in many areas served by our pipelines.
We also faceWith respect to competition among common carrierfrom other pipelines, carrying crude oil. This competition is based primarily onthe primary competitive factors consist of transportation charges, access to crude oil supply and market demand. Similar to pipelines carrying products, the high capital costs deter competitors for the crude oil pipeline systems from building new pipelines. Competitive factors in crude oil purchasing and marketing include price and contract flexibility, quantity and quality of services, and accessibility to end markets.
Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.
Wholesale Fuel Distribution and Retail Marketing
In our wholesale fuel distribution business, we compete primarily with other independent motor fuel distributors. The markets for distribution of wholesale motor fuel and the large and growing convenience store industry are highly competitive and fragmented, which results in narrow margins. We have numerous competitors, some of which may have significantly greater resources and name recognition than we do. Significant competitive factors include the availability of major brands, customer service, price, range of services offered and quality of service, among others. We rely on our ability to provide value-added and reliable service and to control our operating costs in order to maintain our margins and competitive position.
In our retail business, we face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, supermarkets, drugstores, dollar stores, club stores and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending on the geographical area. It also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition. We compete by pricing gasoline competitively, combining our retail gasoline business with convenience stores that provide a wide variety of products, and using advertising and promotional campaigns. We believe that we are in a position to compete effectively as a marketer of refined products because of the location of our retail network, which is well integrated with the distribution system operated by Sunoco Logistics and Sunoco LP.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency

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credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. WeThe Partnership also implement the use ofuses industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies, and midstream companies.independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory

changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
Natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. The discovery and development of new shale formations across the United States has created an abundance of natural gas and crude oil resulting in a negative impact on prices in recent years for natural gas and in recent months for crude oil. As a result, some of our exploration and production customers have been negativelyadversely impacted; however, we are monitoring these customers and mitigating credit risk as necessary.
During the year ended December 31, 2014,2017, none of our customers individually accounted for more than 10% of our consolidated revenues.
Regulation of Interstate Natural Gas Pipelines.  The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act (“NGA”), the FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. The Florida Gas Transmission, Transwestern, Panhandle Eastern, Trunkline Gas, Tiger, Fayetteville Express, and Sea Robin, Gulf States and Midcontinent Express pipelines transport natural gas in interstate commerce and thus each qualifies as a “natural-gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We also hold certain natural gas storage facilities that are subject to the FERC’s regulatory oversight.oversight under the NGA.
The FERC’s NGA authority includes the power to regulate:to:
approve the certificationsiting, construction and constructionoperation of new facilities;
the review and approval ofapprove transportation rates;
determine the types of services that our regulated assets are permitted to perform;
regulate the terms and conditions associated with these services;
permit the extension or abandonment of services and facilities;
require the maintenance of accounts and records; and
authorize the acquisition and disposition of facilities; and
the initiation and discontinuation of services.facilities.
Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are generally required to be on file with the FERC in FERC-approved tariffs.FERC. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition warrants such discounts. Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer a cost-based recourse rate available to a prospective shipper as an alternative to the negotiated rate. Natural gas companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. Existing tariff rates may be challenged by complaint or on FERC’s own motion, and if found unjust and unreasonable, may be altered on a prospective basis from no earlier than the date of the complaint or initiation of a proceeding by the FERC. The FERC must also approve all rate changes. We cannot guarantee that the FERC will allow us to charge rates that fully recover our costs or continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rightspolicies.

For two of access toour NGA-jurisdictional natural gas transportation capacity, transportationcompanies, Tiger and storage facilities.
In 2011, in lieu of filing a new NGA Section 4 general rate case, Transwestern filed a proposed settlement with the FERC, which was approved by the FERC on October 31, 2011. In general, the settlement provides for the continued use of Transwestern’s currently effective transportation and fuel tariff rates, with the exception of certain San Juan Lateral fuel rates, which we were

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required to reduce over a three year period beginning in April 2012. The settlement also resolves certain non-rate matters, and approves Transwestern’s use of certain previously approved accounting methodologies. On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to the 2011 settlement agreement with its shippers.  On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in August 2015.
On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015.
The rates charged for services on the Fayetteville Express, pipeline are largely governed by long-termthe large majority of capacity in those pipelines is subscribed for lengthy terms under FERC-approved negotiated rate agreements. The FERC also approvedrates.  However, as indicated above, cost-based recourse rates available to prospective shippers as an alternative to negotiated rates.
The rates charged for services on the Tiger pipeline are largely governed by long-term negotiated rate agreements.also offered under their respective tariffs.
Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of electric energy or natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction: (i) to defraud using any device, scheme or artifice; (ii) to make any untrue statement of material fact or omit a material fact; or (iii) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). With regard to our physical purchases and sales of natural gas, NGLs or other energy commodities; our gathering or transportation of these energy commodities; and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability

to assess or seek civil penalties of up to approximately $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third partythird-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Failure to comply with the NGA, the Energy Policy Act of 2005, the CEA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.
Regulation of Intrastate Natural Gas and NGL Pipelines.  Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates and terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates and terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline, and ET Fuel System, Trans-Pecos and Comanche Trail are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the TRRC. Our intrastate pipeline and storage operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.
Our NGL pipelines and operations may also be or become subject to state public utility or related jurisdiction which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities.

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Table In addition, the rates, terms and conditions for shipments of ContentsNGLs on our pipelines are subject to regulation by FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all NGLs shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

Regulation of Sales of Natural Gas and NGLs.  The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation.
To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to the use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.
Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those operations of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom we compete.
Regulation of Gathering Pipelines.  Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines in Texas, Louisiana and West Virginia that we believe meet the traditional tests the FERC uses to establish a pipeline’s status as a gatherergathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject

of substantial litigation and varying interpretations, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by the FERC, the courts and Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.
Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.
We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Regulation of Interstate Crude Oil, NGL and Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act (“ICA”),ICA, the Energy Policy ActEPAct of 1992, and related rules and orders. The ICA requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are

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typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariffstariff rates charged by us ultimately will be upheld if challenged, management believes that the tariffstariff rates now in effect for our pipelines are within the maximum rates allowed under current FERC guidelines.policies and precedents.
We have been approved by the FERC to charge market-based rates in most of the productsFor many locations served by our pipeline systems. In those locations where market-based rates have been approved,product and crude pipelines, we are able to establish negotiated rates.  Otherwise, we are permitted to charge cost-based rates, or in many cases, grandfathered rates based on historical charges or settlements with our customers. To the extent we rely on cost-of-service ratemaking to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise. In 2005, FERC issued a policy statement stating that it would permit common carriers, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. Whether a pipeline’s owners have such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for common carriers that are based upon competitive market conditions.organized as pass-through entities, it still entails rate risk due to the FERC’s case-by-case review approach. The application of this policy, as well as any decision by

FERC regarding our cost of service, may also be subject to review in the courts. In December 2016, FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs. FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect to the notice of inquiry ended on April 7, 2017. The outcome of the inquiry is still pending.
Finally, in November 2017 FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline.  In particular, FERC’s November 2017 order prohibits  buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service  is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss.  Several parties have requested that FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order.  We are unable to predict how FERC will respond to such requests.  Depending on how FERC responds, it could have an impact on the rates we are permitted to charge.
EPAct 1992 required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPIFG. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2011 and ending June 30, 2016, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPIFG plus 2.65%. Beginning July 1, 2016, the indexing method provided for annual changes equal to the change in PPIFG plus 1.23%. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior 2 years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules ended on March 17, 2017. FERC has taken no further action on the proposed rule to date.
Finally, in November 2017 FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline.  In particular, FERC’s November 2017 order prohibits  buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service  is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss.  Several parties have requested that FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order.  We are unable to predict how FERC will respond to such requests.  Depending on how FERC responds, it could have an impact on the rates we are permitted to charge.
Regulation of Intrastate Crude Oil, NGL and Products Pipelines. Some of our crude oil, NGL and products pipelines are subject to regulation by the TRRC, the PA PUC, and the Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.
In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of Pipeline Safety.  Our pipeline operations are subject to regulation by the DOT, underthrough the PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. Both the NGPSA and the HLPSA were amended by the Pipeline Safety Improvement Act of 2002 (“PSI Act”) and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”). The NGPSA and HLPSA,

as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Failure to comply with the pipeline safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of administrative, civil and criminal remedies. The “rural gathering exemption” underinvestigatory, remedial or corrective action obligations, the NGPSA presently exempts substantial portionsoccurrence of delays in permitting or the performance of projects, or the issuance of injunctions limiting or prohibiting some or all of our gathering facilities from jurisdiction under the NGPSA, but does not apply to our intrastate natural gas pipelines. The portions of our facilities that are exempt include those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. Changes to federal pipeline safety laws and regulations are being considered by Congress or PHMSA including changes to the “rural gathering exemption,” which may be restrictedoperations in the future. Most recently, in an August 2014 U.S. Government Accountability Office (the “GAO”) report to Congress, the GAO acknowledged PHMSA’s continued assessment of the safety risks posedaffected area.
The HLPSA and NGPSA have been amended by these gathering lines as part of the rulemaking process, and recommended that PHMSA move forward with rulemaking to address larger-diameter, higher-pressure gathering lines, including subjecting such pipelines to emergency response planning requirements that currently do not apply. While we believe our pipeline operations are in substantial compliance with applicable pipeline safety laws, safety laws and regulations may be made more stringent and penalties could be increased. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation service.
Most recently, the NGPSA and HLPSA were amended on January 3, 2012 when President Obama signed into law the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) which increases pipelineand the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”). The 2011 Pipeline Safety Act increased the penalties for safety regulation. Among other things,violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the legislation doublesadoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a related series of violations, and providesbut provided that these maximum penalty caps do not apply to certain civil enforcement actions; permitsactions. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $209,002 per day, with a maximum of $2,090,022 for a series of violations. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the DOT Secretary2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Act also empowers PHMSA to mandate automaticaddress imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or remote controlled shut off valves on newnatural gas pipeline facilities without prior notice or entirely replaced pipelines; requiresan opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the DOT Secretaryagency’s expanded authority to evaluate whether integrity management system requirements should be expanded beyond HCAs, within 18 months of enactment; and provides for regulation of carbon dioxide transported byaddress unsafe pipeline in a gaseous state and requiresconditions or practices that pose an imminent hazard to life, property, or the DOT Secretary to prescribe minimum safety regulations for such transportation.environment.

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In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which we conduct operations typically have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting natural gas and NGLs.pipelines. Under such state regulatory programs, states have the authority to conduct pipeline inspections, to investigate accidents and to oversee compliance and enforcement, safety programs and record maintenance and reporting. Congress, PHMSA and individual states may pass or implement additional safety requirements that could result in increased compliance costs for us and other companies in our industry. For instance,example, federal construction, maintenance and inspection standards under the NGPSA that apply to pipelines in relatively populated areas may not apply to gathering lines running through rural regions. This “rural gathering exemption” under the NGPSA presently exempts substantial portions of our gathering facilities located outside of cities, towns or any area designated as residential or commercial from jurisdiction under the NGPSA, but does not apply to our intrastate natural gas pipelines. In recent years, the PHMSA has considered changes to this rural gathering exemption, including publishing an advance notice of proposed rulemaking relating to gas pipelines in 2011, in which the agency sought public comment on possible changes to the definition of “high consequence areas” and “gathering lines” and the strengthening of pipeline integrity management requirements. In April 2016, pursuant to one of the requirements of the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that, among other things, would expand certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; require natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and require certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has not yet finalized the March 2016 proposed rulemaking.
In January 2017, PHMSA issued a final rule amending federal safety standards for hazardous liquid pipelines. The final rule is the latest step in a lengthy rulemaking process that began in 2010 with a request for comments and continued with publication of a rulemaking proposal in October 2015. The general effective date of this final rule is six months from publication in the Federal Register, but it is currently subject to further administrative review in connection with the transition of Presidential administrations and thus, implementation of this final rule remains uncertain. The final rule addresses several areas including reporting requirements for gravity and unregulated gathering lines, inspections after weather or climatic events, leak detection system requirements, revisions to repair criteria and other integrity management revisions. In addition, PHMSA issued regulations on January 23, 2017, on operator qualification, cost recovery, accident and incident notification and other pipeline safety changes that are now effective. These regulations are also subject, however, to potential further review in connection with the transition of Presidential

administrations. Historically, our pipeline safety costs have not had a material adverse effect on our business or results of operations but there is no assurance that such costs will not be material in the future, whether due to elimination of the rural gathering exemption or otherwise due to changes in pipeline safety laws and regulations.
In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the federal OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators, including the Texas Railroad Commission, have in the recent past,years, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. These recent actions by PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators; however, toTo the extent that such legal challengesthese actions are unsuccessful,pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.
Environmental Matters
General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering, processing, storage and transmission of natural gas and the storage and transportation of NGLs, crude oil and refined products is subject to stringent federal, tribal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and criminal sanctions, third partythird-party claims for personal injury or property damage, capital expenditures to retrofit or upgrade our facilities and programs, or curtailment or cancellation of permits on operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of planning, permitting, constructing and operating our plants, pipelines and other facilities. Included inAs a result of these laws and regulations, our construction and operation costs areinclude capital, operating and maintenance cost items necessary to maintain or upgrade our equipment and facilities to remain in compliance with environmental laws and regulations.facilities.
We have implemented procedures designed to ensure that all governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. We believe thatHistorically, our operations and facilities are in substantialenvironmental compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations willcosts have not havehad a material adverse effect on our business, results of operations andor financial condition. Wecondition; however, there can be no assurance that such costs will not be material in the future. For example, we cannot be certain, however, that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent environmental laws and regulations or other unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.
Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to strict, joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition or that may be subject to other waste disposal laws and regulations. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed.

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We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, as amended, (“RCRA”), and comparable state statutes. We are not currently required to comply with a substantial

portion of the RCRA hazardous waste requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent non-hazardous management standards. From time to time, the EPA has considered or third parties have petitioned the agency on the adoption of stricter handling, storage and disposal standards for nonhazardous wastes, including certain wastes associated with the exploration, development and production of crude oil and natural gas. For example, following the filing of a lawsuit by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the United States District Court for the District of Columbia on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense.expense and, in the case of our oil and natural gas exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in demand for our processing, transportation and storage services.
We currently own or lease sites that have been used over the years by prior owners and lessees and by us for various activities related to gathering, processing, storage and transmission of natural gas, NGLs, crude oil and products. Solid wasteWaste disposal practices within the oil and gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on or under various sites during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.
As of December 31, 20142017 and 2013,2016, accruals of $401$372 million and $403$344 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover estimated material environmental liabilities including, for example, certain matters assumed in connection with our acquisition of the HPL System, our acquisition of Transwestern, potential environmental liabilities for three sites that were formerly owned by Titan Energy Partners, L.P. or its predecessors, and the predecessor owner’s share of certain environmental liabilities of ETC OLP.
The Partnership is subject to extensive and frequently changing federal, tribal, state and local laws and regulations, including those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and composition of fuels. These laws and regulations require environmental assessment and remediation efforts at many of Sunoco, Inc.’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $363$284 million and $377$289 million at December 31, 20142017 and 2013,2016, respectively, which is included in the total accruals above. These legacy sites that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that are no longer operated by Sunoco, Inc., closed and/or sold refineries and other formerly owned sites. In December 2013, a wholly-owned captive insurance company was established for these legacy sites.sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. As of December 31, 20142017 the captive insurance company held $267$207 million of cash and investments.
The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
We have established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
Under various environmental laws, including the RCRA, (which relates to non-hazardous and hazardous waste treatment, storage and disposal), the Partnership has initiated corrective remedial action at certain of its facilities, formerly owned facilities and at certain third-party sites. At the Partnership’s major manufacturing facilities, we have consistentlytypically assumed continued industrial use and a containment/remediation strategy focused on eliminating unacceptable risks to human health or the environment. The remediation accruals for these sites reflect that strategy. Accruals include amounts designed to prevent or mitigate off-site migration and to contain the impact on the facility property, as well as to address known, discrete

areas requiring remediation within the plants. ActivitiesRemedial activities include, for example, closure of RCRA solid waste management units, recovery of hydrocarbons, handling of impacted soil, mitigation of surface water impacts and prevention or mitigation of off-site migration. A change in this approach as a result of changing the intended use of a property or a sale to a third party could result in a comparatively higher cost remediation strategy in the future.

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The Partnership currently owns or operates certain retail gasoline outlets where releases of petroleum products have occurred. Federal and state laws and regulations require that contamination caused by such releases at these sites and at formerly owned sites be assessed and remediated to meet the applicable standards. Our obligation to remediate this type of contamination varies, depending on the extent of the release and the applicable laws and regulations. A portion of the remediation costs may be recoverable from the reimbursement fund of the applicable state, after any deductible has been met.
In general, eacha remediation site or issue is typically evaluated individuallyon an individual basis based upon information available for the site or issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g.,(for example, service station sites) in determining the amount of probable loss accrual to be recorded. The estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance allows thatus the minimum amount of the range be accrued.to accrue. Accordingly, the low end of the range often represents the amount of loss which has been recorded.
In addition to the probable and estimable losses which have been recorded, management believes it is reasonably possible (i.e.,(that is, it is less than probable but greater than remote) that additional environmental remediation losses will be incurred. At December 31, 2014,2017, the aggregate of thesuch additional estimated maximum additional reasonably possible losses, which relate to numerous individual sites, totaled approximately $6 million.$5 million, which amount is in excess of the $372 million in environmental accruals recorded on December 31, 2017. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics and retail assets, and in many cases, reflects the upper end of the loss ranges which are described above. Such estimates include potentially higher contractor costs for expected remediation activities, the potential need to use more costly or comprehensive remediation methods and longer operating and monitoring periods, among other things.
In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years, but management can provide no assurance that it would be over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, ifIf changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time.  As a result, from time to time, significant charges against income for environmental remediation may occur; however,occur. And while management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.position, it can provide no assurance.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $7$5 million, which is included in the total environmental accruals mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. However, suchSuch future costs are not expected to have a material impact on our financial position, results of operations or cash flows.flows, but management can provide no assurance.
Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We will be required to incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. We believe thatHistorically, our operations are in substantialcosts for compliance with the federalexisting Clean Air Act and comparable state laws.law requirements have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. The EPA and state agencies are continuallyoften considering, proposing or finalizing new regulations that could impact our existing operations and the costs and timing of new infrastructure development. For example, in December 2014,October 2015, the EPA published a proposed regulation that it expects to finalize by October 1, 2015, which rulemaking proposed to revise final rule under the Clean Air Act, lowering

the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone

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between 65 to 70 parts per billion (“ppb”) for both the 8-hour primary and secondary ozone standards. The current primaryEPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and secondary ozoneis expected to issue non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are set at 75 ppb. EPA also requested public comments on whether the standard should be set as low as 60 ppb or whether the existing 75 ppb standard should be retained. If EPA lowers the ozone standard, states could be requiredexpected to implement new more stringent regulations,requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.
Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended, also known as (“Clean Water ActAct”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the United States. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. We believe that we are in substantial compliance withThe Clean Water Act permitting requirementsalso prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In May 2015, the EPA issued a final rule that attempts to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the United States Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In June 2015, the EPA and the United States Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the United States Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested May 2015 rule would not take effect until two years after the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the United States Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. On January 31, 2018, the EPA and Corps finalized a rule that would delay applicability of the rule to two years from the rule’s publication in the Federal Register. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, our operations as well as the conditions imposed thereunder,our exploration and that our continued complianceproduction customers’ drilling programs could incur increased costs and delays with such existing permit conditions will not have a material adverse effect on our business, financial condition or results of operations.respect to obtaining permits for dredge and fill activities in wetland areas.
Spills. Our operations can result in the discharge of regulated substances, including NGLs, crude oil or other products. The Clean Water Act, oras amended by the federal Oil Pollution Act of 1990, as amended, (“OPA”), and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. The Clean Water Act and comparable state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges. The OPA subjects owners of covered facilities to strict joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release.release of oil. The PHMSA, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans and our management believes wethat are to be used in substantial compliance with these laws.the event of a spill incident.
In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.
Endangered Species Act. The Endangered Species Act, as amended, restricts activities that may affect endangered or threatened species or their habitat. Similar protection isprotections are offered to migratory birds under the Migratory Bird Treaty Act. We may operate in areas that are currently designated as a habitat for endangered or threatened species or where the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened may occur in which event such one or more developments could cause us to incur additional costs, to develop habitat conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas. Moreover, such designation of previously unprotected species as threatened or endangered in areas where our oil and natural gas exploration and production customers operate could cause our

customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.
Climate Change. Based on findingsClimate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made byand are likely to continue to be made at the EPA thatinternational, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon dioxide, methanetaxes and other greenhouse gases present an endangermentGHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to public health and the environment, thedate. The EPA has, however, adopted regulationsrules under existing provisionsauthority of the federal Clean Air Act that, among other things, establish Prevention ofPotential for Significant Deterioration (“PSD”) construction and Title V permittingoperating permit reviews for greenhouse gas emissionGHG emissions from certain large stationary sources that already are also potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtainemissions, which reviews could require securing PSD permits for their greenhouse gas emissions will be required to also reduce those emissions according toat covered facilities emitting GHGs and meeting “best available control technology” standards for greenhouse gases, which are typically developed by the states. Any regulatory or permitting obligation that limits emissions of greenhouse gases could require us to incur costs to reduce or sequester emissions of greenhouse gases associated with our operations and also could adversely affect demand for the natural gas and other hydrocarbon products that we transport, process, or otherwise handle in connection with our services.
those GHG emissions. In addition, the EPA has adopted regulationsrules requiring the monitoring and annual reporting of greenhouse gasGHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore oil and natural gas production, processing, transmission, storage and distribution facilities. On December 9, 2014,In October 2015, the EPA published a proposed rule that would expandamended and expanded the petroleum and natural gas system sources for which annual greenhouse gas emissions reporting is currently required to include greenhouse gas emissions reporting beginning in the 2016 reporting year for certain onshore gathering and boosting systems consisting primarily of gathering pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas removal. We are monitoring greenhouse gas emissions from certain of our facilities in accordance with current greenhouse emissionsGHG reporting requirements in a manner that we believe is in substantial compliance with applicable reporting obligations and are currently assessingto all segments of the potential impact that the December 9, 2014 proposed rule may have on our future reporting obligations, should the proposal be adopted.

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Various pieces of legislation to reduce emissions of, or to create cap and trade programs for, greenhouse gases have been proposed by the U.S. Congress over the past several years, but no proposal has yet passed. Numerous states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The passage of legislation that limits emissions of greenhouse gases from our equipment and operations could require us to incur costs to reduce the greenhouse gas emissions from our own operations, and it could also adversely affect demand for our transportation, storage and processing services by reducing demand for oil, natural gas and NGLs. For example, in January 2015, the Obama Administration announced plans for the EPA to issue final standards in 2016 that would reduce methane emissions from new and modified oil and natural gas productionindustry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas processingoperations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and transmission facilitiesnatural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by upthe EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, the Subpart OOOOa standards have been subject to 45%attempts by the EPA to stay portions of those standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. This rule, should it remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the United States State Department informed the United Nations of the intent of the United States to withdraw from 2012 levels by 2025.the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.
Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is

difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
Employee Health and Safety. We are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHAOccupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe thatHistorically, our operations are in substantial compliance with thecosts for OSHA requirementsrequired activities, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances.substances, have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
Employees
As of January 30, 2015,December 31, 2017, ETE and its consolidated subsidiaries employed an aggregate of 27,60529,486 employees, 1,6091,544 of which are represented by labor unions. We and our subsidiaries believe that our relations with our employees are satisfactory.
SEC Reporting
We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.
ITEM 1A.  RISK FACTORS
In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. ETP, Regency, Panhandle Sunoco Logistics and Sunoco LP file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information. The risk factors set forth below, and those included in ETP’s, Regency’s, Panhandle’s Sunoco Logistics’ and Sunoco LP’s Annual Report,Reports, are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.
Risks Inherent in an Investment in Us
Cash distributions are not guaranteed and may fluctuate with our performance or other external factors.
The Parent company’s principal source of our earnings and cash flow is cash distributions from ETP Regency and Sunoco Logistics via the Class H Units.LP. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETP Regency orand Sunoco Logistics makesLP make to their partners. ETP Regency orand Sunoco LogisticsLP may not be able to

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continue to make quarterly distributions at their current level or increase their quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP Regency or Sunoco LogisticsLP increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP Regency or Sunoco LogisticsLP to us.
Our ability to distribute cash received from ETP and RegencySunoco LP to our Unitholders is limited by a number of factors, including:
interest expense and principal payments on our indebtedness;
restrictions on distributions contained in any current or future debt agreements;
our general and administrative expenses;
expenses of our subsidiaries other than ETP or Regency,and Sunoco LP, including tax liabilities of our corporate subsidiaries, if any; and
reserves our General Partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors, many of which are beyond our control or the control of our General Partner.
Our only significant assets arecash flow depends primarily on the cash distributions we receive from our partnership interests, including the incentive distribution rights, in ETP and RegencySunoco LP and, therefore, our cash flow is dependent upon the ability of ETP and RegencySunoco LP to make distributions in respect of those partnership interests.
We do not have any significant assets other than our partnership interests in ETP and Regency. Our interest in ETP include Class H Units, for which distributions to us are based on a percentage of the general partnerSunoco LP and incentive distribution right interests in Sunoco Logistics.our LNG business. As a result, our cash flow depends on the performance of ETP Regency and Sunoco LogisticsLP and their respective subsidiaries and ETP’s and Regency’sSunoco LP’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP Regency and Sunoco Logistics.LP.
The amount of cash that ETP Regency and Sunoco LogisticsLP can distribute to their partners, including us, each quarter depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter and will depend upon, among other things:
the amount of natural gas, NGLs, crude oil and refined products transported through ETP’s Regency’s and Sunoco Logistics’ transportation pipelines and gathering systems;
the level of throughput in processing and treating operations;
the fees charged and the margins realized by ETP Regency and Sunoco LogisticsLP for their services;
the price of natural gas, NGLs, crude oil and refined products;
the relationship between natural gas, NGL and crude oil prices;
the amount of cash distributions ETP receives with respect to the Regency and AmeriGasSunoco LP common units that ETP or theirits subsidiaries own;
the weather in their respective operating areas;
the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;
the level of their respective operating costs;costs and maintenance and integrity capital expenditures;
the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;
prevailing economic conditions; and
the level and results of their respective derivative activities.
In addition, the actual amount of cash that ETP and RegencySunoco LP will have available for distribution will also depend on other factors, such as:
the level of capital expenditures they make;
the level of costs related to litigation and regulatory compliance matters;

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the cost of acquisitions, if any;
the levels of any margin calls that result from changes in commodity prices;
debt service requirements;
fluctuations in working capital needs;
their ability to borrow under their respective revolving credit facilities;
their ability to access capital markets;
restrictions on distributions contained in their respective debt agreements; and
the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.
ETE does not have any control over many of these factors, including the level of cash reserves established by the board of directors and ETP’s and Regency’s respective General Partners. Accordingly, we cannot guarantee that ETP Regency orand Sunoco LogisticsLP will have sufficient available cash to pay a specific level of cash distributions to its partners.

Furthermore, Unitholders should be aware that the amount of cash that ETP and RegencySunoco LP have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, ETP and RegencySunoco LP may declare and/or pay cash distributions during periods when they record net losses. Please read “Risks Related to the Businesses of Energy Transfer Partners and Regency Energy Partners”our Subsidiaries” included in this Item 1A for a discussion of further risks affecting ETP’s and Regency’sSunoco LP’s ability to generate distributable cash flow.
We may issue an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.
Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:
our Unitholders’ current proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each Common Unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding Common Unit may be diminished; and
the market price of our Common Units may decline.
In addition, ETP and RegencySunoco LP may sell an unlimited number of limited partner interests without the consent of the respective Unitholders, which will dilute existing interests of the respective Unitholders, including us. The issuance of additional Common Units or other equity securities by ETP or Sunoco LP will have essentially the same effects as detailed above.
ETP or Regencyand Sunoco LP may issue additional Common Units, which may increase the risk that ETP or Regencyeach Partnership will not have sufficient available cash to maintain or increase its per unit distribution level.
The partnership agreements of each ETP and RegencySunoco LP allow ETP and Regency, respectively,each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by ETP or Regencyeach respective partnership will have the following effects:
Unitholders’ current proportionate ownership interest in ETP or Regency, as applicable,each partnership will decrease;
the amount of cash available for distribution on each common unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of ETP’s or Regency’s Common Units, as applicable, may decline.
The payment of distributions on any additional units issued by ETP or Regency may increase the risk that ETP or Regency, as applicable, may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.

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Sunoco Logistics and Sunoco LP may issue additional common units, which may increase the risk that Sunoco Logistics or Sunoco LP will not have sufficient available cash to maintain or increase their per unit distribution level.
Sunoco Logistics’ and Sunoco LP’s partnership agreements allow the issuance of an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by Sunoco Logistics or Sunoco LP will have the following effects:
Unitholders’ current proportionate ownership interest in Sunoco Logistics and Sunoco LP, as applicable, will decrease;
the amount of cash available for distribution on each common unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of Sunoco Logistics’ and Sunoco LP’spartnership’s common units may decline.
The payment of distributions on any additional units issued by Sunoco LogisticsETP and Sunoco LP may increase the risk that Sunoco Logistics and Sunoco LPeither partnership may not have sufficient cash available to maintain or increase theirits per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.
Unitholders have limited voting rights and are not entitled to elect the General Partner or its directors. In addition, even if Unitholders are dissatisfied, they cannot easily remove the General Partner.
Unlike the holders of common stock in a corporation, Unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner and will have no right to elect our General Partner or the officers or directors of our General Partner on an annual or other continuing basis.
Furthermore, if our Unitholders are dissatisfied with the performance of our General Partner, they may be unable to remove our General Partner. Our General Partner may not be removed except, among other things, upon the vote of the holders of at least 66 2/3% of our outstanding units. As of December 31, 2014,2017, our directors and executive officers directly or indirectly own approximately 20%27% of our outstanding Common Units. It will be particularly difficult for our General Partner to be removed without the consent of our directors and executive officers. As a result, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

Furthermore, Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the General Partner and its affiliates, cannot be voted on any matter. If the Regency Merger is completed and the Bakken Pipeline Transaction is completed, ETE’s aggregate ownership percentage of the outstanding ETP Common Units would decrease to approximately 5% on a pro forma basis.
Our General Partner may, in its sole discretion, approve the issuance of partnership securities and specify the terms of such partnership securities.
Pursuant to our partnership agreement, our General Partner has the ability, in its sole discretion and without the approval of the Unitholders, to approve the issuance of securities by the Partnership at any time and to specify the terms and conditions of such securities. The securities authorized to be issued may be issued in one or more classes or series, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership securities), as shall be determined by our General Partner, including:
the right to share in the Partnership’s profits and losses;
the right to share in the Partnership’s distributions;
the rights upon dissolution and liquidation of the Partnership;
whether, and the terms upon which, the Partnership may redeem the securities;
whether the securities will be issued, evidenced by certificates and assigned or transferred; and
the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.
Please see “—We may issue an unlimited number of limited partner interests without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.” above.

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The control of our General Partner may be transferred to a third party without Unitholder consent.
The General Partner may transfer its general partner interest to a third party without the consent of the Unitholders. Furthermore, the members of our General Partner may transfer all or part of their ownership interest in our General Partner to a third party without the consent of the Unitholders. Any new owner or owners of our General Partner or the general partner of the General Partner would be in a position to replace the directors and officers of our General Partner with its own choices and to control the decisions made and actions taken by the board of directors and officers.
We are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative and legal services necessary to operate our business.
We rely on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETP’s midstream business, as well as other key members of ETP’s management team such as Marshall S. (Mackie) McCrea, III, President and Chief Operating Officer.business. Mr. Warren and Mr. McCrea havehas been integral to the success of ETP’s midstream and intrastate transportation and storage businesses because of theirhis ability to identify and develop strategic business opportunities. Losing the leadership of either Mr. Warren or Mr. McCrea could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.
ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.
Cost reimbursements due to our General Partner may be substantial and may reduce our ability to pay the distributions to our Unitholders.
Prior to making any distributions to our Unitholders, we will reimburse our General Partner for all expenses it has incurred on our behalf. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our General Partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to our Unitholders. Our General Partner has sole discretion to determine the amount of these expenses and fees.
In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our General Partner.

To the extent our General Partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our General Partner, our General Partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our Unitholders and cause the value of our Common Units to decline.
A reduction in ETP’s or Regency’sSunoco LP’s distributions will disproportionately affect the amount of cash distributions to which we areETE is entitled.
Through our ownershipETE indirectly owns all of equity interests inthe IDRs of ETP GP,and Sunoco LP. These IDRs entitle the holder of the incentive distribution rights in ETP, we are entitled to receive our pro rata share of specifiedincreasing percentages of total cash distributions made by each of ETP and Sunoco LP as itsuch entity reaches established target cash distribution levels as specified in the ETPits partnership agreement. WeETE currently receive ourreceives its pro rata share of cash distributions from ETP and Sunoco LP based on the highest incremental percentage,sharing level of 48%, to which and 50% in respect of the ETP GP is entitled pursuant to its incentive distribution rights in ETP. IDRs and Sunoco LP IDRs, respectively.
A decrease in the amount of distributions by ETP to ETE to less than $0.4125$0.2638 per Common Unitunit per quarter would reduce ETP GP’sETE’s percentage of the incremental cash distributions from ETP above $0.3175$0.0958 per Common Unitunit per quarter from 48% to 23%35%, and a decrease in the amount of distributions by Sunoco LP to ETE to less than $0.6563 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from Sunoco LP above $0.5469 per unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash distributions from the ETP or Sunoco LP would have the effect of disproportionately reducing the amount of all distributions that weETE and ETP receive, from ETP based on ourtheir ownership interest in the incentive distribution rights in ETPIDRs as compared to cash distributions wethey receive from ETP on our General Partnertheir general partner interest and common units in ETP and our ETP Common Units.
Similarly, we currently receive a pro rata share of incremental cash distributions from Regency at the 23% level pursuant to Regency GP’s incentive distribution rights in Regency as specified in the Regency partnership agreement. A decrease in the amount of distributions by Regency to less than $0.4375 per Common Unit per quarter would have reduced Regency GP’s percentage of the incremental cash distributions above $0.4025 per Common Unit per quarter from 23% to 13%. As a result, any such reduction in quarterly cash distributions from Regency would have the effect of disproportionately reducing the amount of all distributions that we receive from Regency based on our ownership interest in the incentive distribution rights of Regency as compared to cash distributions we receive from Regency on our General Partner interest in Regency and our Regency Common Units.

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A reduction in Sunoco Logistics’ distributions will disproportionately affect the amount of cash distributions to which we are entitled.
Through our ownership of equity interests in Sunoco Partners, the holder of the incentive distribution rights in Sunoco Logistics, we are entitled to receive our pro rata share of specified percentages of total cash distributions made by Sunoco Logistics as it reaches established target cash distribution levels as specified in the Sunoco Logistics partnership agreement. We currently receive our pro rata share of cash distributions from Sunoco Logistics based on the highest incremental percentage, 48%, to which Sunoco Partners is entitled pursuant to its incentive distribution rights in Sunoco Logistics. A decrease in the amount of distributions by Sunoco Logistics to less than $0.2638 per common unit per quarter would reduce Sunoco Partners’ percentage of the incremental cash distributions above $0.0958 per common unit per quarter from 48% to 35%. As a result, any such reduction in quarterly cash distributions from Sunoco Logistics would have the effect of disproportionately reducing the amount of all distributions that we receive from Sunoco Logistics based on our ownership interest in the incentive distribution rights in Sunoco Logistics as compared to cash distributions we receive from Sunoco Logistics on our General Partner interest in Sunoco Logistics and our Sunoco Logistics common units.entity.
The consolidated debt level and debt agreements of ETP and RegencySunoco LP and those of their subsidiaries may limit the distributions we receive from ETP and Regency,Sunoco LP, as well as our future financial and operating flexibility.
ETP’s and Regency’sSunoco LP’s levels of indebtedness affect their operations in several ways, including, among other things:
a significant portion of ETP’s Regency’sand Sunoco LP’s and their subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;
covenants contained in ETP’s Regency’sand Sunoco LP’s and their subsidiaries’ existing debt agreements require ETP, RegencySunoco LP and their subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;
ETP’s Regency’sand Sunoco LP’s and their subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
ETP and RegencySunoco LP may be at a competitive disadvantage relative to similar companies that have less debt;
ETP and RegencySunoco LP may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels; and
failure by ETP, RegencySunoco LP or their subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETP’s and Regency’sSunoco LP’s ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions.distributions to us and their unitholders.
We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt at maturity.
Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our Available Cash (as defined in our partnership agreement) to our Unitholders of record and our General Partner. Available Cash is generally all of our cash on hand as of the end of a quarter, adjusted for cash distributions and net changes to reserves. Our General Partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:
to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);
to provide funds for distributions to our Unitholders and our General Partner for any one or more of the next four calendar quarters; or
to comply with applicable law or any of our loan or other agreements.

A downgrade of our credit ratingratings could impact our and our subsidiaries’ liquidity, access to capital and our costs of doing business, and maintaining credit ratings is under the control of independent third parties.
A downgrade of our credit ratingratings might increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratingratings and other disruptions. Such disruptions could include:
economic downturns;

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deteriorating capital market conditions;
declining market prices for crude oil, natural gas, NGLs and other commodities;
terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.
Our subsidiaries are not prohibited from competing with us.
Neither our partnership agreement nor the partnership agreements of our subsidiaries, including ETP Sunoco Logistics,and Sunoco LP, and Regency, prohibit our subsidiaries from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.
Capital projects will require significant amounts of debt and equity financing, which may not be available to ETP or Regency on acceptable terms, or at all.
ETP and Regency planplans to fund theirits growth capital expenditures, including any new future pipeline construction projects and improvements or repairs to existing facilities that ETP or Regency may undertake, with proceeds from sales of ETP’s or Regency’s debt and equity securities and borrowings under their respectiveits revolving credit facilities;facility; however, ETP or Regency cannot be certain that theyit will be able to issue debt and equity securities on terms satisfactory to them,it, or at all. In addition, ETP or Regency may be unable to obtain adequate funding under theirits current revolving credit facility because ETP’s or Regency’s lending counterparties may be unwilling or unable to meet their funding obligations. If ETP or Regency areis unable to finance theirits expansion projects as expected, ETP or Regency could be required to seek alternative financing, the terms of which may not be attractive to ETP, or Regency, or to revise or cancel its expansion plans.
A significant increase in ETP’s or Regency’s indebtedness that is proportionately greater than ETP’s or Regency’s respective issuancesissuance of equity could negatively impact ETP’s or Regency’s respective credit ratings or theirits ability to remain in compliance with the financial covenants under their respectiveits revolving credit agreements,agreement, which could have a material adverse effect on ETP’s or Regency’s financial condition, results of operations and cash flows.
Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates. Approximately $5.89$9.86 billion of our consolidated debt as of December 31, 20142017 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates. We manage a portion of our interest rate exposures by utilizing interest rate swaps.
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment opportunities may cause the trading price of our Common Units to decline.
The credit and risk profile of our General Partner and its owners could adversely affect our credit ratings and profile.
The credit and business risk profiles of our General Partner or indirect owners of our General Partner may be factors in credit evaluations of us as a publicly traded limited partnership due to the significant influence of our General Partner and indirect owners over our business activities, including our cash distributions, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our General Partner and its owners, including the degree of their financial leverage and their dependence on cash flow from us to service their indebtedness.
ETE has significant indebtedness outstanding and is dependent principally on the cash distributions from its general and limited partner equity interests in us and in Regency to service such indebtedness. Any distributions by us to ETE will be made only after satisfying our then current obligations to our creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us, ETP GP and ETP LLC from the entities that

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control ETP GP (ETE and its general partner), our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of such entities were viewed as substantially lower or riskier than ours.
Unitholders may have liability to repay distributions.
Under certain circumstances, Unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law, will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to pay distributions to our Unitholders and to service our debt depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. If we are unable to obtain funds from our subsidiaries we may not be able to pay distributions to our Unitholders or to pay interest or principal on our debt when due.
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Our partnership agreement allows the general partner to incur obligations on our behalf that are expressly non-recourse to the general partner. The general partner has entered into such limited recourse obligations in most instances involving payment liability and intends to do so in the future.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Our debt level and debt agreements may limit our ability to make distributions to Unitholders and may limit our future financial and operating flexibility.flexibility and may require asset sales.
As of December 31, 20142017, we had approximately $30.66$6.70 billion of debt on a stand-alone basis and approximately $44.08 billion of consolidated debt, excluding the debt of our joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:
a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;
covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;
our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
we may be at a competitive disadvantage relative to similar companies that have less debt;
we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and
failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.
UnitholdersIn order for us to manage our debt levels, we may need to sell assets, issue additional equity securities, reduce the cash distributions we pay to our unitholders or a combination thereof. In the event that we sell assets, the future cash generating capacity of our remaining asset base may be requireddiminished. In the event that we issue additional equity securities, we may need to issue these securities at a time when our common unit price is depressed and therefore we may not receive favorable prices for our common units or favorable prices or terms for other types of equity securities. In the event we reduce cash distributions on our common units, the public trading price of our common units could decline significantly.
Our General Partner has a limited call right that may require Unitholders to sell their units to our general partner at an undesirable time or price.
If at any time less than 10% of the outstanding units of any class are held by persons other than the general partnerour General Partner and its affiliates the general partnerown more than 90% of our outstanding units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of thosethe units held by unaffiliated persons at a price nonot less than their then-current

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market price. As a consequence, a unitholderresult, Unitholders may be required to sell his Common Unitstheir units at an undesirable time or price. The general partnerprice and may assign this purchase right tonot receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2017, the directors and executive officers of our General Partner owned approximately 27% of our Common Units.

Litigation commenced by WMB against ETE and its affiliates could cause ETE to incur substantial costs, may present material distractions and, if decided adverse to ETE, could negatively impact ETE’s financial position and credit ratings.
WMB filed a complaint against ETE and its affiliates in the Delaware Court of Chancery, alleging that the defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates.  Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the merger agreement by ETE on June 29, 2016, WMB filed a notice of appeal to the Supreme Court of Delaware.  WMB filed an amended complaint on September 16, 2016 and seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement. The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by WMB’s misconduct. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that WMB breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, WMB filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on WMB’s motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.  On January 11, 2017, the parties held oral argument before the Delaware Supreme Court on WMB’s appeal of the June 24 ruling. The Delaware Supreme Court has taken the matter under advisement. These lawsuits could result in substantial costs to ETE, including litigation costs and settlement costs. ETE believes that the time required by the management of ETE and its counsel to defend against the allegations made by WMB in the litigation against ETE and its affiliates is likely to be substantial and the time required by the officers and employees of LE GP, assuming WMB actively pursues such litigation, is also likely to be substantial. The defense or to us.settlement of any lawsuit or claim that remains unresolved may result in negative media attention, and may adversely affect ETE’s business, reputation, financial condition, results of operations, cash flows and market price.
Risks Related to Conflicts of Interest
Although we control ETP and RegencySunoco LP through our ownership of their respective General Partners,general partners, ETP’s General Partner owesand Sunoco LP’s general partners owe fiduciary duties to ETP and ETP’s Unitholders,unitholders and Regency’s General Partner owes fiduciary duties to RegencySunoco LP and Regency’s Unitholders,Sunoco LP’s unitholders, respectively, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and ETP Regencyand Sunoco LP and their respective limited partners, on the other hand. The directors and officers of ETP’s and Regency’sSunoco LP’s General Partners have fiduciary duties to manage ETP and Regency,Sunoco LP, respectively, in a manner beneficial to us. At the same time, the General Partners have fiduciary duties to manage ETP and Regency, respectively,Sunoco LP in a manner beneficial to ETP Regencyand Sunoco LP and their respective limited partners. The boardboards of directors of ETP’s and Sunoco LP’s General Partner or Regency’s general partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.
For example, conflicts of interest with ETP or Regencyand Sunoco LP may arise in the following situations:
the allocation of shared overhead expenses to ETP, RegencySunoco LP and us;
the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP or Regency,and Sunoco LP, on the other hand;
the determination of the amount of cash to be distributed to ETP’s or Regency’sand Sunoco LP’s partners and the amount of cash to be reserved for the future conduct of ETP’s or Regency’s business;and Sunoco LP’s businesses;
the determination whether to make borrowings under ETP’s or Regency’s respectiveand Sunoco LP’s revolving credit facilityfacilities to pay distributions to ETP’s or Regency’s partners, as applicable;their respective partners;
the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of ETP or Regencyand Sunoco LP is made available for either ETP or Regency, or both,and Sunoco LP to pursue; and
any decision we make in the future to engage in business activities independent of ETP or Regency.and Sunoco LP.

The fiduciary duties of our General Partner’s officers and directors may conflict with those of ETP’s or Regency’sSunoco LP’s respective General Partners.general partners.
Conflicts of interest may arise because of the relationships among ETP, Regency,Sunoco LP, their General Partnersgeneral partners and us. Our General Partner’sgeneral partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our General Partner’s directors are also directors and officers of ETP’s General Partnergeneral partner or Regency’s General Partner,Sunoco LP’s general partner, and have fiduciary duties to manage the respective businesses of ETP and RegencySunoco LP in a manner beneficial to ETP, RegencySunoco LP and their respective Unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.
Potential conflicts of interest may arise among our General Partner, its affiliates and us. Our General Partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.
Conflicts of interest may arise among our General Partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:
Our General Partner is allowed to take into account the interests of parties other than us, including ETP Regencyand Sunoco LP and their respective affiliates and any General Partnersgeneral partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.
Our General Partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
Our General Partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.
Our General Partner determines which costs it and its affiliates have incurred are reimbursable by us.

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Our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.
Our General Partner controls the enforcement of obligations owed to us by it and its affiliates.
Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our partnership agreement limits our General Partner’s fiduciary duties to us and restricts the remedies available for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
provides that our General Partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit and Conflicts Committee of the board of directors of our General Partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
provides that unless our General Partner has acted in bad faith, the action taken by our General Partner shall not constitute a breach of its fiduciary duty;
provides that our General Partner may resolve any conflicts of interest involving us and our General Partner and its affiliates, and any resolution of a conflict of interest by our General Partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the partnership agreement;

provides that our General Partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the General Partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us; and
provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
Our General Partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 90% of our outstanding units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2014, the directors and executive officers of our General Partner owned approximately 20% of our Common Units.
The general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our Unitholders.
Our partnership agreement requires the general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, our partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

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Risks Related to the Businesses of ETP and Regencyour Subsidiaries
Since our cash flows consist exclusively of distributions from ETP and Regency,our subsidiaries, risks to the businesses of ETP and Regencyour subsidiaries are also risks to us. We have set forth below risks to the businesses of ETP and Regency,our subsidiaries, the occurrence of which could have a negative impact on their respective financial performance and decrease the amount of cash they are able to distribute to us.
ETP and Regency dodoes not control, and therefore may not be able to cause or prevent certain actions by, certain of theirits joint ventures.
Certain of ETP’s and Regency’s joint ventures have their own governing boards, and ETP or Regency may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for ETP or Regency to cause the joint venture entity to take actions that ETP or Regency believebelieves would be in their or the joint venture’s best interests. Likewise, ETP or Regency may be unable to prevent actions of the joint venture.
ETP and RegencySunoco LP are exposed to the credit risk of their respective customers and derivative counterparties, and an increase in the nonpayment and nonperformance by their respective customers or derivative counterparties could reduce their respective ability to make distributions to their Unitholders, including to us.
The risks of nonpayment and nonperformance by ETP’s and Regency’sSunoco LP’s respective customers are a major concern in their respective businesses. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP and RegencySunoco LP are subject to risks of loss resulting from nonpayment or nonperformance by their respective customers. Thecustomers, especially during the current low commodity price environment impacting many oil and gas producers. As a result, the current commodity price volatility and the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s and Regency’sSunoco LP’s customers. To the extent one or more of our customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our Unitholders. Any substantial increase in the nonpayment and nonperformance by ETP’s or Regency’sSunoco LP’s customers could have a material adverse effect on ETP’s or Regency’sSunoco LP’s respective results of operations and operating cash flows.
The use of derivative financial instruments could result in material financial losses by ETP and Sunoco LP.
From time to time, ETP and Sunoco LP have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by their trading, marketing and/or system optimization activities. To the extent that either ETP or Sunoco LP hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change favorably. In addition, ETP’s and Sunoco LP’s derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to ETP’s or Sunoco LP’s physical or financial positions, or internal hedging policies and procedures are not followed.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
In addition, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.
The inability to continue to access lands owned by third parties, including tribal lands, could adversely affect ETP’s and Sunoco LP’s ability to operate and adversely affect their financial results.
ETP’s ability to operate its pipeline systems and terminal facilities on certain lands owned by third parties, including lands held in trust by the United States for the benefit of a Native American tribe, will depend on their success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. Securing extensions of existing and any additional rights-of-way is also critical to ETP’s ability to pursue expansion projects. ETP cannot provide any assurance that they will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants or that all of the rights-of-way will be obtainable in a timely fashion. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively. ETP’s financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.
Further, whether ETP has the power of eminent domain for its pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state. In either case, ETP must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect ETP’s business if they were to lose the right to use or occupy the property on which their pipelines are located. For example, following a recent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. Any loss of rights with respect to ETP’s real property, through its inability to renew right-of-way contracts or otherwise, could have a material adverse effect on its business, results of operations, financial condition and ability to make cash distributions.
In addition, Sunoco LP does not own all of the land on which their retail service stations are located. Sunoco LP has rental agreements for approximately 35.2% of the company-operated retail service stations where Sunoco LP currently controls the real estate and has rental agreements for certain logistics facilities. As such, Sunoco LP is subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Sunoco LP is also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by Sunoco LP are leased from third parties for specific periods. Sunoco LP’s inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on its financial condition, results of operations and cash flows.
ETP and Sunoco LP may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.
ETP and Sunoco LP have strategies that contemplate growth through the development and acquisition of a wide range of midstream, retail and wholesale fuel distribution assets and other energy infrastructure assets while maintaining strong balance sheets. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP and Sunoco LP regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that ETP and Sunoco LP believe will present opportunities to realize synergies and increase cash flow.
Consistent with their strategies, managements of ETP and Sunoco LP may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP and Sunoco LP management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP and Sunoco LP believe it is the only party or one of a very limited number of potential buyers

in negotiations with the potential seller. We cannot assure that ETP’s or Sunoco LP’s acquisition efforts will be successful or that any acquisition will be completed on favorable terms.
In addition, ETP and Sunoco LP are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETP or Sunoco LP losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s and Sunoco LP’s ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETP’s and Sunoco LP’s results of operations.
An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2017, our consolidated balance sheets reflected $4.77 billion of goodwill and $6.12 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.
During the fourth quarter of 2017, we performed goodwill impairment tests on our reporting units and recognized goodwill impairments at both ETP and Sunoco LP. The goodwill impairments at ETP consisted of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations and $452 million in its all other operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. During the year 2017, Sunoco LP recorded a goodwill impairment charge of $102 million on its retail reporting unit.

During the fourth quarter of 2016, we performed goodwill impairment tests on our reporting units and recognized goodwill impairments at both ETP and Sunoco LP. The goodwill impairments recognized at ETP consisted of $638 million related to ETP’s interstate transportation and storage operations and $32 million related to ETP’s midstream operations. These impairments are primarily due to decreases in projected future revenues and cash flows driven by reduced volumes as a result of overall declining commodity prices and changes in the markets that these assets serve. During the fourth quarter of 2016, Sunoco LP recognized a goodwill impairment of $641 million in its retail reporting unit primarily due to changes in assumptions related to projected future revenues and cash flows from the dates this goodwill was originally recorded. During the fourth quarter of 2016, Sunoco LP also recognized a $32 million impairment on its Laredo Taco brand name intangible asset primarily due to changes in Sunoco LP’s construction plan for new-to-industry sites and decreases in sales volume in oil field producing regions where Sunoco LP has operations.
If ETP and Sunoco LP do not make acquisitions on economically acceptable terms, their future growth could be limited.
ETP’s and Sunoco LP’s results of operations and their ability to grow and to increase distributions to Unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.
ETP and Sunoco LP may be unable to make accretive acquisitions for any of the following reasons, among others:
inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
inability to raise financing for such acquisitions on economically acceptable terms; or
inability to outbid by competitors, some of which are substantially larger than ETP or Sunoco LP and may have greater financial resources and lower costs of capital.
Furthermore, even if ETP or Sunoco LP consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP or Sunoco LP may:
fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;
significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;
encounter difficulties operating in new geographic areas or new lines of business;

incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which there is no indemnity or the indemnity is inadequate;
be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;
less effectively manage its historical assets, due to the diversion of management’s attention from other business concerns; or
incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
If ETP and Sunoco LP consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETP and Sunoco LP determine the application of their funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that ETP and Sunoco LP will consider.
Integration of assets acquired in past acquisitions or future acquisitions with our existing business will be a complex and time-consuming process. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to our unitholders.
The difficulties of integrating past and future acquisitions with our business include, among other things:
operating a larger combined organization in new geographic areas and new lines of business;
hiring, training or retaining qualified personnel to manage and operate our growing business and assets;
integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;
diversion of management’s attention from our existing business;
assimilation of acquired assets and operations, including additional regulatory programs;
loss of customers or key employees;
maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and
integrating new technology systems for financial reporting.
If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions resulting in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.
Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems, and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, may not be observable even when an inspection is undertaken.
Legal actions related to the Dakota Access Pipeline could cause an interruption to operations, which could have an adverse effect on our business and results of operations.
On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. The Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (the “Court”) against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline and claimed violations of the National Historic Preservation Act (“NHPA”). Dakota Access intervened in the case.
In February 2017, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. The SRST and Cheyenne River Sioux Tribe (“CRST”) (which had intervened in the lawsuit brought by SRST), amended their complaints to incorporate religious freedom and other claims related to treaties and use of government property. The Oglala and

Yankton Sioux tribes, and various individual members, filed related lawsuits in opposition to the Dakota Access pipeline. These lawsuits have been consolidated into the action initiated by the SRST.
On June 14, 2017, the Court ruled that the USACE substantially complied with all relevant statutes in connection with the issuance of the permits and easement, but remanded to the USACE three discrete issues for further analysis and explanation of its prior determination under certain of these statutes. On October 11, 2017, the Court ruled that the pipeline could continue to transport crude oil during the pendency of the remand, but requested briefing from the parties as to whether any conditions on the continued operation of the pipeline during this period. On December 4, 2017, the Court determined to impose three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. Second, the Court directed Dakota Access to continue its work with the tribes and the USACE to revise and finalize its response planning for the section of the pipeline crossing Lake Oahe. Third, the Court directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information recommended by PHMSA.
While we believe that the pending lawsuits are unlikely to adversely affect the continued operation of the pipeline, we cannot assure this outcome. At this time, we cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
In addition, lawsuits of this nature could result in interruptions to construction or operations of future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.
Income from ETP’s midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs and crude oil that are beyond our control.
The prices for natural gas, NGLs and crude oil (including refined petroleum products) reflect market demand that fluctuates with changes in global and U.S.United States economic conditions and other factors, including:
the level of domestic natural gas, NGL, and crude oil production;
the level of natural gas, NGL, and crude oil imports and exports, including liquefied natural gas;
actions taken by natural gas and oil producing nations;
instability or other events affecting natural gas and oil producing nations;
the impact of weather and other events of nature on the demand for natural gas, NGLs and crude oil;
the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;
the price, availability and marketing of competitive fuels;
the demand for electricity;
activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;
the cost of capital needed to maintain or increase production levels and to construct and expand facilities
the impact of energy conservation and fuel efficiency efforts; and
the extent of governmental regulation, taxation, fees and duties.
In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and we expect this volatility to continue.
Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs or crude oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGLNGLs and crude oil commodities could materially affect our profitability
A material decrease in demand or distribution of crude oil available for transport through Sunoco Logistics’ pipelines or terminal facilities could materially and adversely affect our results of operations, financial position, or cash flows.
The volume of crude oil transported through Sunoco Logistics’ crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by its assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases

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in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to Sunoco Logistics’ customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in Sunoco Logistics’ crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all. If Sunoco Logistics is unable to replace any significant volume declines with additional volumes from other sources, our results of operations, financial position, or cash flows could be materially and adversely affected.profitability.
ETP and Regency areis affected by competition from other midstream, transportation and storage and retail marketing companies.
We experience competition in all of our business segments. With respect to ETP’s midstream operations, ETP competes for both natural gas supplies and customers for its services. Competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.
ETP’s and Regency’s natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas

and NGLs also competescompete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.
In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.
ETP’s crude oil and refined products pipeline operations face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in areas served by Sunoco Logistics’ pipelines. Further, our refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.
ETP also faces strong competition in the market for the sale of retail gasoline and merchandise. ETP’s competitors include service stations operated by fully integrated major oil companies and other well-recognized national or regional retail outlets, often selling gasoline or merchandise at aggressively competitive prices. The actions of retail marketing competitors, including the impact of foreign imports, could lead to lower prices or reduced margins for the products we sell, which could have an adverse effect on our business or results of operations.
ETP and Regency may be unable to retain or replace existing midstream, transportation, terminalling and storage customers or volumes due to declining demand or increased competition in crude oil, natural gas and NGL markets, which would reduce revenues and limit future profitability.
The retention or replacement of existing customers and the volume of services that ETP and Regency provideprovides at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of and demand for crude oil, natural gas, and NGLs in the markets we serve and competition from other service providers.
A significant portion of ETP and Regency’sETP’s sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in natural gas sales markets primarily on the basis of price.
ETP and Regency also receivereceives a substantial portion of revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of their services are sold under long-term contracts for reserved service, they also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services, while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers’ business. If demand declines or competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.

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Revenue from ETP and Regency’sETP’s NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. ETP and Regency receivereceives substantially all of their transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to their transportation system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, ETP’s refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, a portion of its revenue is derived from fungible storage and throughput arrangements, under which ETP’s revenue is more dependent upon demand for storage from its customers.
The volume of crude oil and products transported through ETP’s oil pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. A period of sustained increases in the price of crude oil or products supplied from or delivered to any of these areas could materially reduce demand for crude oil or products in these areas. In either case, the volumes of crude oil or products transported in our oil pipelines and terminal facilities could decline.
The loss of existing customers by ETP and Regency’sETP’s midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services customers purchase from them, or their inability to attract new customers and service volumes would negatively affect revenues, be detrimental to growth, and adversely affect results of operations.

ETP’s midstream facilities and transportation pipelines are attached to basins with naturally declining production, which it may not be able to replace with new sources of supply.
In order to maintain or increase throughput levels on ETP’s gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, ETP must continually contract for new natural gas supplies and natural gas transportation services.
A substantial portion of ETP’s assets, including its gathering systems and processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. ETP’s gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. ETP may not be able to obtain additional contracts for natural gas supplies for its natural gas gathering systems, and may be unable to maintain or increase the levels of natural gas throughput on its transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to its transportation pipelines or markets to which ETP’s systems connect. ETP has no control over the level of drilling activity in its areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, ETP has no control over producers or their production and contracting decisions.
While a substantial portion of ETP’s services are provided under long-term contracts for reserved service, it also provides service on an unreserved basis. The reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities may decline and may not be replaced by other sources of supply. A decrease in development or production activity could cause a decrease in the volume of unreserved services ETP provides and a decrease in the number and volume of its contracts for reserved transportation service over the long run, which in each case would adversely affect revenues and results of operations.
If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.
ETP is entirely dependent upon third parties for the supply of refined products such as gasoline and diesel for its retail marketing business.
ETP is required to purchase refined products from third party sources, including the joint venture that acquired Sunoco, Inc.’s Philadelphia refinery. ETP may also need to contract for new ships, barges, pipelines or terminals which it has not historically used to transport these products to its markets. The inability to acquire refined products and any required transportation services at favorable prices may adversely affect ETP’s business and results of operations.

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The profitability of certain activities in ETP’s and Regency’s natural gas gathering, processing, transportation and storage operations areis largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.
For a portion of the natural gas gathered on ETP’s and Regency’s systems, they purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where they typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins they realizerealized under these arrangements decrease in periods of low natural gas prices.
ETP and Regency also enterenters into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which wethey agree to gather and process natural gas received from the producers.
Under percent-of-proceeds arrangements, ETP and Regency generally sellsells the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, ETP and Regency deliverdelivers an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes ETP and Regency keepkept to third parties at market prices. Under these arrangements, ETP’s revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on ETP’s and Regency’s revenues and results of operations.
Under keep-whole arrangements, ETP and Regency generally sellsells the NGLs produced from ourtheir gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, ETP and Regency must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.
When ETP and Regency processprocesses the gas for a fee under processing fee agreements, they may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, ETP or Regency may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.
ETP and Regency also receivereceives fees and retainretains gas in kind from our natural gas transportation and storage customers. ETP and Regency’sThe fuel retention fees and the value of gas that they retainETP retains in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease these fuel retention fees and the value of retained gas.

In addition, ETP receives revenue from itstheir off-gas processing and fractionating system in Southsouth Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of ourETP’s off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for ETP’stheir off-gas processing and fractionation services and could have an adverse effect on ETP’stheir results of operations.
For ETP’s midstream operations, gross margin is generally analyzed based on fee-based margin (which includes revenues from processing fee arrangements) and non-fee based margin (which includes gross margin earned on percent-of-proceeds and keep-whole arrangements). For the years ended December 31, 2017, 2016 and 2015, gross margin from ETP’s midstream operations totaled $2.18 billion, $1.80 billion, and $1.79 billion, respectively, of which fee-based revenues constituted 78%, 86% and 88%, respectively, and non-fee based margin constituted 22%, 14% and 12%, respectively. The useamount of derivative financial instruments could resultgross margin earned by ETP’s midstream operations from fee-based and non-fee based arrangements (individually and as a percentage of total revenues) will be impacted by the volumes associated with both types of arrangements, as well as commodity prices; therefore, the dollar amounts and the relative magnitude of gross margin from fee-based and non-fee based arrangements in material financial losses by ETP and Regency.
From time to time, ETP and Regency have sought to reduce our exposure to fluctuationsfuture periods may be significantly different from results reported in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by their trading, marketing and/or system optimization activities. To the extent that either ETP or Regency hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change favorably. In addition, even though monitored by management, ETP’s and Regency’s derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to ETP’s or Regency’s physical or financial positions, or internal hedging policies and procedures are not followed.
The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
In addition, even though monitored by management, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge

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is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.previous periods.
ETP’s and Regency’s natural gas and NGL revenues depend on theirits customers’ ability to use ETP’s and Regency’s pipelines and third-party pipelines over which we have no control.
ETP’s and Regency’s natural gas transportation, storage and NGL businesses depend, in part, on their customers’ ability to obtain access to pipelines to deliver gas to and receive gas from ETP and Regency.ETP. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third partythird-party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material adverse effect on ETP’s and Regency’s ability, and the ability of their customers, to transport natural gas to and from their pipelines and facilities and a corresponding material adverse effect on their transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from ETP’s and Regency’ss facilities affect the utilization and value of their storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on storage revenues.
Shippers using ETP’s and Regency’s oil pipelines and terminals are also dependent upon their pipelines and connections to third-party pipelines to receive and deliver crude oil and products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in ETP’s and Regency’s pipelines or through their terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to ETP and Regency’s existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in their pipelines or through their terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on ETP and Regency’sETP’s results of operations, financial position, or cash flows.
The inability to continue to access lands owned by third parties, including tribal lands, could adversely affect our ability to operate and adversely affect our financial results.
Our ability to operate our pipeline systems and terminal facilities on certain lands owned by third parties, including lands held in trust by the United States for the benefit of a Native American tribe, will depend on our success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. Securing extensions of existing and any additional rights-of-way is also critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants or that all of the rights-of-way will be obtainable in a timely fashion. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.
Further, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state. In either case, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located.
In addition, we do not own all of the land on which our oil terminal facilities and our retail service stations are located. We have rental agreements for approximately 41.8% of the company- or dealer-operated retail service stations where we currently control the real estate and we have rental agreements for certain logistics facilities. As such, we are subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. We are also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods. Our inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on our financial condition, results of operations and cash flows.
ETP and Regency may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.
ETP and Regency each have strategies that contemplate growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining strong balance sheets. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP and Regency regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that ETP and Regency believe will present opportunities to realize synergies and increase cash flow.

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Consistent with their strategies, managements of ETP and Regency may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP or Regency management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP or Regency believes it is the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot assure that ETP’s or Regency’s acquisition efforts will be successful or that any acquisition will be completed on favorable terms.
In addition, ETP and Regency each are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETP or Regency losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s or Regency’s ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETP’s or Regency’s results of operations.
An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2014, our consolidated balance sheets reflected $7.87 billion of goodwill and $5.58 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.
During the fourth quarter of 2013, we recorded a goodwill impairment charge of $689 million on our Lake Charles LNG reporting unit. During the fourth quarter of 2014, a $370 million goodwill impairment was recorded related to Regency’s Permian Basin gathering and processing operations. See Note 2 to our consolidated financial statements for additional information.
If ETP and Regency do not make acquisitions on economically acceptable terms, their future growth could be limited.
ETP’s and Regency’s results of operations and their ability to grow and to increase distributions to Unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.
ETP and Regency may be unable to make accretive acquisitions for any of the following reasons, among others:
inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
inability to raise financing for such acquisitions on economically acceptable terms; or
inability to outbid by competitors, some of which are substantially larger than ETP or Regency and may have greater financial resources and lower costs of capital.
Furthermore, even if ETP or Regency consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP or Regency may:
fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;
significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;
encounter difficulties operating in new geographic areas or new lines of business;
incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which there is no indemnity or the indemnity is inadequate;
be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;
less effectively manage its historical assets, due to the diversion of management’s attention from other business concerns; or
incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
If ETP and Regency consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETP and Regency determine the application of their funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that ETP and Regency will consider.

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If ETP and Regency dodoes not continue to construct new pipelines, their future growth could be limited.
ETP’s and Regency’s results of operations and their ability to grow and to increase distributable cash flow per unit will depend, in part, on their ability to construct pipelines that are accretive to their respective distributable cash flow. ETP or Regency may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:
inability to identify pipeline construction opportunities with favorable projected financial returns;
inability to raise financing for its identified pipeline construction opportunities; or
inability to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.
Furthermore, even if ETP or Regency constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or fail to achieve results projected prior to commencement of construction.
Expanding ETP’s and Regency’s business by constructing new pipelines and related facilities subjects ETP and Regency to risks.
One of the ways that ETP and Regency havehas grown their respective businessesbusiness is through the construction of additions to existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline and related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond ETP’s and Regency’s control and requirerequires the expenditure of significant amounts of capital to be financed through borrowings, the issuance of additional equity or from operating cash flow. If ETP or Regency undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. A variety of factors outside ETP’s or Regency’s control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors may result in increased costs or delays

in construction. Cost overruns or delays in completing a project could have a material adverse effect on ETP’s or Regency’s results of operations and cash flows. Moreover, revenues may not increase immediately following the completion of a particular project. For instance, if ETP or Regency builds a new pipeline, the construction will occur over an extended period of time, but ETP or Regency, as applicable, may not materially increase its revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s and Regency’s abilitiesability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, ETP and Regency may construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s or Regency’s expected investment return, which could adversely affect its results of operations and financial condition.
ETP and Regency dependdepends on certain key producers for a significant portion of their supplies of natural gas. The loss of, or reduction in, any of these key producers could adversely affect ETP’s or Regency’s respective business and operating results.
ETP and Regency relyrelies on a limited number of producers for a significant portion of their natural gas supplies. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, ETP and Regency will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. ETP and Regency may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on ETP’s and Regency’s business, results of operations, and financial condition.
ETP and Regency dependdepends on key customers to transport natural gas through their pipelines.
ETP and Regency relyrelies on a limited number of major shippers to transport certain minimum volumes of natural gas on their respective pipelines, and Regency maintains contracts for compression services with a limited number of key customers.pipelines. The failure of the major shippers on ETP’s Regency’s or their joint ventures’ pipelines or of other key customers to fulfill their contractual obligations under these contracts could have a material adverse effect on the cash flow and results of operations of us, ETP Regency or their joint ventures, as applicable, were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
Mergers among Sunoco Logistics’ customersETP’s contract compression operations depend on particular suppliers and competitorsare vulnerable to parts and equipment shortages and price increases, which could resulthave a negative impact on results of operations.
The principal manufacturers of components for ETP’s natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers and Ariel Corporation for compressors and frames. ETP’s reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in lower volumes being shippeda timely manner. ETP also relies primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble its compression units. ETP does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships.
A material decrease in demand or distribution of crude oil available for transport through ETP’s pipelines or products stored in or distributed through its terminals, or reduced crude oil marketing margins or volumes.
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of Sunoco Logistics’ systems in those markets where the systems compete. As a result, Sunoco Logistics could

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lose some or all of the volumes and associated revenues from these customers and could experience difficulty in replacing those lost volumes and revenues, whichterminal facilities could materially and adversely affect our results of operations, financial position, or cash flows.
The volume of crude oil transported through ETP’s crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by its assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to ETP’s customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in ETP’s crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all. If ETP is unable to replace any significant volume declines with additional volumes from other sources, its results of operations, financial position, or cash flows could be materially and adversely affected.
An interruption of supply of crude oil to ETP’s facilities could materially and adversely affect our results of operations and revenues.
While ETP is well positioned to transport and receive crude oil by pipeline, marine transport and trucks, rail transportation also serves as a critical link in the supply of domestic crude oil production to United States refiners, especially for crude oil from regions such as the Bakken that are not sourced near pipelines or waterways that connect to all of the major United States refining centers. Federal regulators have issued a safety advisory warning that Bakken crude oil may be more volatile than many other North American crude oils and reinforcing the requirement to properly test, characterize, classify, and, if applicable, sufficiently degasify hazardous materials prior to and during transportation. The domestic crude oil received by our facilities, especially from the Bakken region, may be transported by railroad. If the ability to transport crude oil by rail is disrupted because of accidents,

weather interruptions, governmental regulation, congestion on rail lines, terrorism, other third-party action or casualty or other events, then ETP could experience an interruption of supply or delivery or an increased cost of receiving crude oil, and could experience a decline in volumes received. Recent railcar accidents in Quebec, Alabama, North Dakota, Pennsylvania and Virginia, in each case involving trains carrying crude oil from the Bakken region, have led to increased legislative and regulatory scrutiny over the safety of transporting crude oil by rail. In 2015, the DOT, through the PHMSA, issued a rule implementing new rail car standards and railroad operating procedures. Changing operating practices, as well as new regulations on tank car standards and shipper classifications, could increase the time required to move crude oil from production areas of facilities, increase the cost of rail transportation, and decrease the efficiency of transportation of crude oil by rail, any of which could materially reduce the volume of crude oil received by rail and adversely affect our financial condition, results of operations, and cash flows.
A portion of Sunoco Logistics’ETP’s general and administrative services have been outsourced to third-party service providers. Fraudulent activity or misuse of proprietary data involving its outsourcing partners could expose us to additional liability.
Sunoco LogisticsETP utilizes both affiliate entities and third parties in the processing of its information and data. Breaches of its security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about Sunoco LogisticsETP or its customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose Sunoco LogisticsETP to a risk of loss or misuse of this information, result in litigation and potential liability for Sunoco Logistics,ETP, lead to reputational damage, increase compliance costs, or otherwise harm its business.
ETPSunoco LP is entirely dependent upon third parties for the supply of refined products such as gasoline and Regency’sdiesel for its retail marketing business.
Sunoco LP is required to purchase refined products from third party sources, including the joint venture that acquired Sunoco, Inc.’s Philadelphia refinery. Sunoco LP may also need to contract for new ships, barges, pipelines or terminals which it has not historically used to transport these products to its markets. The inability to acquire refined products and any required transportation services at favorable prices may adversely affect Sunoco LP’s business and results of operations.
A significant decrease in demand for motor fuel, including increased consumer preference for alternative motor fuels or improvements in fuel efficiency, in the areas Sunoco LP serves would reduce their ability to make distributions to unitholders.
Sales of refined motor fuels account for approximately 93% of Sunoco LP’s total revenues and 62% of continuing operations gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and their ability to make or increase distributions to unitholders. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience declines in their profit margin if fuel distribution volumes decrease.
Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change customers' shopping habits or lead to new forms of fueling destinations or new competitive pressures.
New technologies have been developed and governmental mandates have been implemented to improve fuel efficiency, which may result in decreased demand for petroleum-based fuel. Any of these outcomes could result in fewer visits to Sunoco LP’s convenience stores or independently operated commission agents and dealer locations, a reduction in demand from their wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.

The industries in which Sunoco LP operates are subject to seasonal trends, which may cause our operating costs to fluctuate, affecting our cash flow.

Sunoco LP relies in part on customer travel and spending patterns, and may experience more demand for gasoline in the late spring and summer months than during the fall and winter. Travel, recreation and construction are typically higher in these months in the geographic areas in which Sunoco LP or its commission agents and dealers operate, increasing the demand for motor fuel that they sell and distribute. Therefore, Sunoco LP’s revenues and cash flows are typically higher in the second and third quarters of our fiscal year. As a result, Sunoco LP’s results from operations may vary widely from period to period, affecting Sunoco LP’s cash flow.

Sunoco LP’s financial condition and results of operations are influenced by changes in the prices of motor fuel, which may adversely impact margins, customers’ financial condition and the availability of trade credit.
Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.
Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.
The dangers inherent in the storage and transportation of motor fuel could cause disruptions in Sunoco LP’s operations and could expose them to potentially significant losses, costs or liabilities.
Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a material adverse effect on its business, financial condition, results of operations and cash available for distribution to unitholders.
Sunoco LP’s fuel storage terminals are subject to operational and business risks which may adversely affect their financial condition, results of operations, cash flows and ability to make distributions to unitholders.
Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following:
the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;
the dependence on third parties to supply their fuel storage terminals;
outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;
the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;
the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;
the effects of a sustained recession or other adverse economic conditions;
the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products;
competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and
climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.
The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s business, financial condition, results of operations, cash flows and ability to make distributions to unitholders.
Negative events or developments associated with Sunoco LP’s branded suppliers could have an adverse impact on its revenues.
Sunoco LP believes that the success of its operations is dependent, in part, on the continuing favorable reputation, market value, and name recognition associated with the motor fuel brands sold at Sunoco LP’s convenience stores and at stores operated by its independent, branded dealers and commission agents. Erosion of the value of those brands could have an adverse impact on the

volumes of motor fuel Sunoco LP distributes, which in turn could have a material adverse effect on its business, financial condition, results of operations and ability to make distributions to its unitholders.
The wholesale motor fuel distribution industry and convenience store industry are characterized by intense competition and fragmentation and impacted by new entrants. Failure to effectively compete could result in lower margins.
The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-added, reliable services and to control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.
The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently operated commission agents and dealers sell in stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.
In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse effect on its business, results of operations and cash available for distribution to unitholders.
Sunoco LP expect to generate a significant portion of its motor fuel sales under a fuel supply agreement with 7-Eleven, and any loss, or change in the economic terms, of such arrangement could adversely affect Sunoco LP’s business, financial condition and results of operations.
Sunoco LP expect that a significant portion of its motor fuel sales in 2018 will be derived from its fuel supply agreement with 7-Eleven. The 7-Eleven fuel supply agreement is a 15-year fixed margin, “take or pay” fuel supply arrangement with certain affiliates of 7-Eleven. The loss or change in economics of such arrangement and the inability to enter into new contracts on similar economically acceptable terms could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations.
Wholesale cost increases in tobacco products, including excise tax increases on cigarettes, could adversely impact Sunoco LP’s revenues and profitability.
Significant increases in wholesale cigarette costs and tax increases on cigarettes may have an adverse effect on unit demand for cigarettes. Cigarettes are subject to substantial and increasing excise taxes at both a state and federal level. Sunoco LP cannot predict whether this trend will continue into the future. Increased excise taxes may result in declines in overall sales volume and reduced gross profit percent, due to lower consumption levels and to a shift in consumer purchases from the premium to the non-premium or discount segments or to other lower-priced tobacco products or to the import of cigarettes from countries with lower, or no, excise taxes on such items.
Currently, major cigarette manufacturers offer rebates to retailers. Sunoco LP includes these rebates as a component of its gross margin from sales of cigarettes. In the event these rebates are no longer offered, or decreased, Sunoco LP’s wholesale cigarette costs will increase accordingly. In general, Sunoco LP attempts to pass price increases on to its customers. However, due to competitive pressures in our markets, it may not be able to do so. These factors could materially impact Sunoco LP’s retail price of cigarettes, cigarette unit volume and revenues, merchandise gross profit and overall customer traffic, which could in turn have a material adverse effect on Sunoco LP’s business and results of operations.

Failure to comply with state laws regulating the sale of alcohol and cigarettes may result in the loss of necessary licenses and the imposition of fines and penalties, which could have a material adverse effect on Sunoco LP’s business.
State laws regulate the sale of alcohol and cigarettes. A violation of or change in these laws could adversely affect Sunoco LP’s business, financial condition and results of operations because state and local regulatory agencies have the power to approve, revoke, suspend or deny applications for, and renewals of, permits and licenses relating to the sale of these products and can also seek other remedies. Such a loss or imposition could have a material adverse effect on Sunoco LP’s business and results of operations.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. A disruption in supply or a change in either relationship could have a material adverse effect on its business.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to unitholders.
Sunoco LP may be subject to adverse publicity resulting from concerns over food quality, product safety, health or other negative events or developments that could cause consumers to avoid its retail locations or independently operated commission agent or dealer locations.
Sunoco LP may be the subject of complaints or litigation arising from food-related illness or product safety which could have a negative impact on its business. Negative publicity, regardless of whether the allegations are valid, concerning food quality, food safety or other health concerns, food service facilities, employee relations or other matters related to its operations may materially adversely affect demand for its food and other products and could result in a decrease in customer traffic to its retail stores or independently operated commission agent or dealer locations.
It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name recognition.
Sunoco LP has outsourced various functions related to its retail marketing business to third-party service providers, which decreases its control over the performance of these functions. Disruptions or delays of its third-party outsourcing partners could result in increased costs, or may adversely affect service levels. Fraudulent activity or misuse of proprietary data involving its outsourcing partners could expose it to additional liability.
Sunoco LP has previously outsourced various functions related to its retail marketing business to third parties and expects to continue this practice with other functions in the future. While outsourcing arrangements may lower its cost of operations, they also reduce its direct control over the services rendered. It is uncertain what effect such diminished control will have on the quality or quantity of products delivered or services rendered, on its ability to quickly respond to changing market conditions, or on its ability to ensure compliance with all applicable domestic and foreign laws and regulations. Sunoco LP believes that it conducts appropriate due diligence before entering into agreements with its outsourcing partners. Sunoco LP relies on its outsourcing partners to provide services on a timely and effective basis. Although Sunoco LP continuously monitor the performance of these third parties and maintain contingency plans in case they are unable to perform as agreed, it does not ultimately control the performance of its outsourcing partners. Much of its outsourcing takes place in developing countries and, as a result, may be subject to geopolitical uncertainty. The failure of one or more of its third-party outsourcing partners to provide the expected services on a timely basis at the prices Sunoco LP expect, or as required by contract, due to events such as regional economic, business, environmental or political events, information technology system failures, or military actions, could result in significant disruptions and costs to its operations, which could materially adversely affect its business, financial condition, operating results and cash flow. Sunoco LP’s failure to generate significant cost savings from these outsourcing initiatives could adversely affect its profitability and weaken its competitive position. Additionally, if the implementation of its outsourcing initiatives is disruptive to its retail marketing business, Sunoco LP could experience transaction errors, processing inefficiencies, and the loss of sales and customers, which could cause its business and results of operations to suffer. As a result of these outsourcing initiatives, more third parties are involved in processing its retail marketing information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about its retail marketing business or its clients, including the potential loss or disclosure of such information or data as a result of fraud or other forms of

deception, could expose it to a risk of loss or misuse of this information, result in litigation and potential liability for it, lead to reputational damage to the Sunoco brand, increase its compliance costs, or otherwise harm its business.
ETP’s interstate natural gas pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.
Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of ETP’s and Regency’s interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.
ETP and Regency areis required to file tariff rates (also known as recourse rates) with the FERC that shippers may elect to pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. ETP and Regency must also file with the FERC all negotiated rates that do not conform to our tariff rates and all changes to our tariff or negotiated rates. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.
The FERC may review existing tariffstariff rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against ETP or Regency and find that theirits rates were not just and reasonable or unduly discriminatory, the maximum rates customers could elect to pay ETP and Regency may be reduced and the reduction could have an adverse effect on theirour revenues and results of operations.
The costs of ETP’s and Regency’s interstate pipeline operations may increase and ETP or Regency may not be able to recover all of those costs due to FERC regulation of theirits rates. If ETP or Regency proposeproposes to change theirits tariff rates, theirits proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit ETP’s or Regency’s proposed changes if they areETP is unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. ETP and Regency also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or ETP and Regency may be constrained by competitive factors from charging their tariff rates.
To the extent ETP’s and Regency’s costs increase in an amount greater than theirits revenues increase, or there is a lag between theirits cost increases and their ability to file for and obtain rate increases, theirETP’s operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. ETP and Regency cannot guarantee that theirits interstate pipelines will be able to recover all of their costs through existing or future rates.
The ability of interstate pipelines held in tax-pass-through entities, like us,ETP, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. It is currently the FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, ifto the extent that the ultimate owner of the interest hasowners have an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Under the FERC’s policy, weETP thus remainremains eligible to include an income tax allowance in the tariff rates we chargeETP charges for interstate natural gas transportation. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC issued the Notice of Inquiry in response to a remand from the United States Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The effectivenesscomment period with respect to the notice of inquiry ended on April 7, 2017. The outcome of the inquiry is still pending. ETP cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as part of a master limited partnership or decreases the return on equity for such pipelines could result in an adverse impact on ETP’s revenues associated with the transportation and storage services ETP provides pursuant to cost-based rates.
Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. Following the 2017 Tax Cuts and Jobs Act being signed into law, filings have been made at FERC requesting that FERC require pipelines to lower their transportation rates to account for lower taxes. Following the effective date of the law, the FERC orders granting certificates to construct proposed pipeline facilities have directed pipelines proposing new rates for service on those facilities to re-file such rates so that the rates reflect the reduction in the corporate tax rate, and

FERC has issued data requests in pending certificate proceedings for proposed pipeline facilities requesting pipelines to explain the impacts of the reduction in the corporate tax rate on the rate proposals in those proceedings and to provide re-calculated initial rates for service on the proposed pipeline facilities. FERC may enact other regulations or issue further requests to pipelines regarding the impact of the corporate tax rate change on the rates. The FERC’s policyestablishment of a just and reasonable rate is based on many components, and the applicationreduction in the corporate tax rate may impact two of that policy remains subject to future challenges, refinement or change bysuch components: the allowance for income taxes and the amount for accumulated deferred income taxes. Because ETP’s existing jurisdictional rates were established based on a higher corporate tax rate, FERC or ETP’s shippers may challenge these rates in the courts.future, and the resulting new rate may be lower than the rates ETP currently charges.

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TheETP’s interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect theirits business and operations.
In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of ETP’s and Regency’s interstate natural gas pipelines, including:
operating terms and conditions of service;
the types of services interstate pipelines may or must offer their customers;
construction of new facilities;
acquisition, extension or abandonment of services or facilities;
reporting and information posting requirements;
accounts and records; and
relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
Compliance with these requirements can be costly and burdensome. In addition, weETP cannot guarantee that the FERC will authorize tariff changes and other activities weit might propose to do soundertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof in these areas may impair the ability of ETP’s and Regency’s interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.
The current FERC Chairman announced in December 2017 that FERC will review its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. ETP is unable to predict what, if any, changes may be proposed that will affect its natural gas pipeline business or when such proposals, if any, might become effective. ETP does not expect that any change in this policy would affect them in a materially different manner than any other similarly sized natural gas pipeline company operating in the United States.
Rate regulation or market conditions may not allow ETP to recover the full amount of increases in the costs of its crude oil, NGL and products pipeline operations.
Transportation provided on ETP’s common carrier interstate crude oil, NGL and products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If ETP proposes new or changed rates, the FERC or interested persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The primary ratemaking methodology used by the FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. The FERC’s ratemaking methodologies may limit our ability to set rates based on our costs or may delay the use of rates that reflect increased costs. In addition,October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior two years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules ended March 17, 2017. FERC has not yet taken any further action on the proposed rule. If the FERC’s indexing methodology changes, the new methodology could materially and adversely affect our financial condition, results of operations or cash flows.

Under the Energy Policy Act adopted inEPAct of 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.
If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.
State regulatory measures could adversely affect the business and operations of ETP and Regency’sETP’s midstream and intrastate pipeline and storage assets.
ETP’s and Regency’s midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects their business and the market for their products. The rates, terms and conditions of service for the interstate services they provide in their intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. ETP’s HPL System, East Texas pipeline, Oasis pipeline and ET Fuel System provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth

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in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than ETP’s or Regency’s costs of service, their cash flow would be negatively affected.
ETP and Regency’sETP’s midstream and intrastate gas and oil transportation pipelines and their intrastate gas storage operations are subject to state regulation. All of the states in which they operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which ETP and Regency operateoperates have ratable take statutes, which generally require gatherers to take, without undue discrimination, production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, ETP’s or Regency’s businesses may be adversely affected.
ETP’s and Regency’s intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the TRRC. Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.
ETP and Regency areis subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations of state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.
Certain of ETP’s and Regency’s assets may become subject to regulation.
The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of extensive litigation and may be determined by the FERC on a case-by-case basis, although the FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.
Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Lone Star’s NGL Pipeline transports NGLs within the state of Texas and is subject to regulation by the TRRC. This NGLs transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. In 2013, Lone Star’s NGL pipeline also commenced the interstate transportation of NGLs, in 2013, which is subject to FERC’s jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992. Both intrastate and interstate NGL transportation services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a negotiated agreement; however, if FERC’s rate makingratemaking methodologies were imposed, they may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the rates, terms and conditions for shipments of crude oil, petroleum products and NGLs on our pipelines are subject to regulation by FERC if the NGLs are transported in interstate or foreign commerce, whether by our pipelines or other means of transportation.

Since we do not control the entire transportation path of all crude oil, petroleum products and NGLs on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
In addition, if any of our pipelines were found to have provided services or otherwise operated in violation of the NGA, NGPA, or ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to these assets.
ETP and Regency may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to authority under the NGPSA and HLPSA, as amended, by the PSI Act, the PIPES Act and the 2011 Pipeline Safety Act, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,”HCAs which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas.
These regulations require operators of covered pipelines to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline operations that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.

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In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For instance, changesexample, in January 2017, PHMSA issued a final rule for hazardous liquid pipelines that significantly expands the reach of certain PHMSA integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to regulations governinga HCA. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the safetydate of implementation of this final rule by publication in the Federal Register is uncertain given the recent change in Presidential Administrations. In a second example, in April 2016, PHMSA published a proposed rulemaking that would impose new or more stringent requirements for certain natural gas transmission pipelineslines and gathering lines are being considered by PHMSA, including, among other things, expanding certain of PHMSA’s current regulatory safety programs for example, revising the definitions of “highnatural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring gas pipelines installed before 1970 and “gathering lines”thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressure (“MOAP”); and strengtheningrequiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements as they applyand also require consideration of seismicity in evaluating threats to existing regulated operators and to currently exempt operators should certain exemptions be removed. Most recently, in an August 2014 GAO report to Congress, the agency acknowledged PHMSA’s continued assessment of the safety risks posedpipelines. The changes adopted or proposed by these gathering lines as partrulemakings or made in future legal requirements could have a material adverse effect on ETP’s results of rulemaking process,operations and recommended that PHMSA move forward with rulemaking to address such lines.costs of transportation services.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
The NGPSA and HLPSA were amended by the 2011 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids pipelines.Act. Among other things, the 2011 Pipeline Safety Act directsincreased the penalties for safety violations and directed the Secretary of Transportation to promulgate regulationsrules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength testing,of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressureMAOP of certain interstate natural gas transmission pipelines. TheEffective April 27, 2017, maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $209,002 per day, with a maximum of $2,090,022 for a series of violations. In June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural

gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also increases the maximum penalty for violationempowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of natural gas or hazardous liquid pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and from $1.0 million to $2.0 millionfacilities without prior notice or an opportunity for a related series of violations.hearing. PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as further amended by the 2016 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require usETP to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in ourETP incurring increased operating costs that could be significant and have a material adverse effect on ourETP’s results of operations or financial position.condition.
ETP’s and Regency’s businesses involvebusiness involves the generation, handling and disposal of hazardous substances, hydrocarbons and wastes, and may be adversely affected bywhich activities are subject to environmental and worker health and safety laws and regulations.regulations that may cause ETP to incur significant costs and liabilities.
ETP’s and Regency’s operations arebusiness is subject to stringent federal, tribal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for ETP’sthe construction and Regency’s operations,operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit, or prevent emissions, discharges or releases of various materials from ETP’s and Regency’s pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from ETP’s construction and Regency’s operations.operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective obligations, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property and natural resource damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or wastes into the environment.
ETP and Regency may incur substantial environmental costs and liabilities because of the underlying risk inherent toarising out of its operations. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation costs, liabilities foror natural resource damages that could substantially increase our costs for site remediation projects. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.
Changes in environmental laws and regulations occur frequently, and any such changes that result in significantly more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on ETP’s and Regency’s operations or financial position. For example, in December 2014,October 2015, the EPA published a proposed regulation that it expects to finalize by October 1, 2015, which rulemaking proposed to revisefinal rule under the Clean Air Act, lowering the NAAQS for ground-level ozone between 65 to 70 ppbparts per billion for both the 8-hour primary and secondary ozone standards. The current primaryEPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and secondary ozoneis expected to issue non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are set at 75 ppb. EPA also requested public comments on whether the standard should be set as low as 60 ppb or whether the existing 75 ppb standard should be retained. If EPA lowers the ozone standard, states could be requiredexpected to implement more stringent regulations,

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this new final rule, which could apply to ourETP’s customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new emission controls on some of ourETP’s equipment, result in longer permitting timelines or new restrictions or prohibitions with respect to permits or projects, and significantly increase ourits capital expenditures and operating costs, which could adversely impact ourits business. Historically, ETP and Regency have previouslyhas been able to satisfy the more stringent NOxnitrogen oxide emission reduction requirements that affect its compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that ETP and Regencyit will not incur material costs in the future to meet anythe new, more stringent ozone standard.
Product liability claims and litigation could adversely affect our subsidiaries business and results of operations.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.

Along with other refiners, manufacturers and sellers of gasoline, Sunoco, Inc. is a defendant in numerous lawsuits that allege methyl tertiary butyl ether (“MTBE”) contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to Sunoco, Inc. TheseAn adverse determination of liability related to these allegations or other product liability claims against Sunoco, Inc. could have a material adverse effect on our business or results of operations.
The adoption of climateClimate change legislation or regulations restricting emissions of greenhouse gases“greenhouse gases” could result in increased operating costs and reduced demand for the services we provide.
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, determined that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA hashowever, adopted rules under authority of the Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for greenhouse gasGHG emissions from certain large stationary sources that already are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting greenhouse gasesGHGs and meeting “best"best available control technology”technology" standards for those greenhouse gasGHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of greenhouse gasGHG emissions from specified onshore and offshore production facilities and onshore processing, transmission and storage facilities in the United States, which includes certain of our operations. More recently, on December 9, 2014, the EPA published a proposed rule that would expand the petroleum and natural gas system sources for which annual greenhouse gas emissions reporting is currently required to include greenhouse gas emissions reporting beginning in the 2016United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting year for certain onshorerequirements to all segments of the oil and natural gas industry, including gathering and boosting systems consisting primarilyfacilities and blowdowns of gathering pipelines,natural gas transmission pipelines.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and process equipment used to performimposing leak detection and repair requirements for natural gas compression, dehydrationcompressor and acid gas removal. While Congress has from timebooster stations. However, the Subpart OOOOa standards have been subject to time considered adopting legislationattempts by the EPA to reduce emissionsstay portions of greenhouse gases, therethose standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not been significant activityyet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the form2016 standards is uncertain at this time. This rule, should it remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to ETP’s operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect ETP’s business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of adopted legislation.the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the absenceUnited States State Department informed the United Nations of such federal climate legislation,the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a numberfour-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of state and regional efforts have emerged that are aimed at trackingNovember 2020. The United States’ adherence to the exit process and/or reducing greenhouse gas emissions by means of cap and trade programs. the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that requiresrequire reporting of greenhouse gasesGHGs or otherwise restrictsrestrict emissions of greenhouse gases from our equipmentGHGs could result in increased compliance costs or additional operating restrictions, and operations could require us to incur significant added costs to reduce emissions of greenhouse gases or could adversely affecthave a material adverse effect on ETP’s business, financial condition, demand for its services, results of operations, and cash flows. Recently, activists concerned about the natural gaspotential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and NGLs we gather and processother sources of capital restricting or fractionate. For example,eliminating their investment in January 2015, the Obama Administration announced plans for the EPA to issue final standards in 2016 that would reduce methane emissions from new and modified oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas processingwill continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded

that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and transmission facilities by up to 45 percent from 2012 levels by 2025.severity of storms, droughts, and floods and other climate events that could have an adverse effect on ETP’s assets.
The adoptionswaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative instruments to reducemitigate the effectrisks of changes in commodity price,prices and interest raterates and other risks associated with our business, resulting in our operations becoming more volatile and our cash flows less predictable.business.
Congress has adoptedProvisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"“Dodd-Frank Act”) and rules adopted by the Commodity Futures Trading Commission (the “CFTC”), a comprehensive financial reform legislation that establishesthe SEC and other prudential regulators establish federal oversight and regulation of the physical and financial derivatives, including over-the-counter derivatives market and entities, such as us, that participateparticipating in that market. This legislation was signed into law by President Obama on July 21, 2010 and requires the CFTC, the SEC and other regulators to promulgate rules andWhile most of these regulations implementing the new legislation. While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing and we cannot yet predict the ultimate effect of the rules and regulations on our business.
The Dodd-Frank Act expanded the types of entities that are required to register with the CFTC continues to review and the SEC asrefine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, of their activities in the derivatives marketsany new regulations or otherwise become specifically qualifiedmodifications to enter into derivatives contracts. We will be

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required to assess our activities in the derivatives markets, and to monitor such activities on an ongoing basis, to ascertain and to identify any potential change in our regulatory status.
Reporting and recordkeeping requirements alsoexisting regulations could significantly increase operating costs and expose usthe cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability and/or liquidity of derivatives to penalties for non-compliance, and require additional compliance resources. Added public transparency as a result of the reporting rules may also have a negative effect on market liquidity which could also negatively impact commodity prices andprotect against risks we encounter, reduce our ability to hedge.monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.
In October 2011, theThe CFTC has also issued regulations to setre-proposed speculative position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. However, in September 2012, the CFTC’s position limits rules were vacated by the U.S. District Court for the District of Columbia. In November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions forequivalents, although certain bona fide hedging transactions. Astransactions would be exempt from these new position limit ruleslimits provided that various conditions are not yet final, the impact of those provisions on us is uncertain at this time.
satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limits rule and its finalized companion rule on aggregation may create additional implementation or operational exposure. In addition to the CFTC federal speculative position limit regime, designated contract markets (“DCMs”) also maintain speculative position limit and accountability regimes with respect to contracts listed on their platform as well as aggregation requirements similar to the CFTC’s final aggregation rule. Any speculative position limit regime, whether imposed at the federal-level or at the DCM-level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.
The Dodd-Frank Act requires that certain interest rateclasses of swaps be cleared on a derivatives clearing organization and credit default swaps for mandatorytraded on a DCM or other regulated exchange, unless exempt from such clearing and exchange trading.trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The associated rules require us, in connection with covered derivative activities, to comply with suchCFTC and prudential regulators have also adopted mandatory margin requirements or take steps tofor uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for an exemption to such requirements. We must obtain approval from the board of directors of our General Partner and make certain filings in order to rely on theupon an end-user exception from the mandatorysuch clearing and margin requirements for the swaps enteredwe enter into to hedge our commercial risks. TheHowever, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may changeadversely affect the cost and availability of the swaps that we use for hedging. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing and exchange trading.
In addition to the Dodd-Frank Act, requires thatthe European Union and other foreign regulators establish margin rules for uncleared swaps. The application of such requirements to other market participants, such as swap dealers, may changehave adopted and are implementing local reforms generally comparable with the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact our liquidity and reduce cash available to us for capital expenditures, reducing our ability to execute hedges to reduce risk and protect cash flow.
Rules promulgatedreforms under the Dodd-Frank Act further defined forwards as well as instances where forwardsAct. Implementation and enforcement of these regulatory provisions may become swaps. Because the CFTC rules, interpretations, no-action letters, and case law are still developing, it is possible that some arrangements that previously qualified as forwards or energy service contracts may fall in the regulatory category of swaps or options. In addition, the CFTC’s rules applicable to trade options may further impose burdens on our ability to conduct our traditional hedging operations and could become subject to CFTC investigations in the future.
The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, or reduce our ability to monetize or restructure existing derivative contracts. If we reducehedge our usemarket risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of derivatives as a result of the legislationregulatory equivalency across jurisdictions may increase compliance costs and regulations,make it more difficult to satisfy our results of operations may become more volatile and our cash flows may be less predictable. Finally, if we fail to comply with applicable laws, rules or regulations, we may be subject to fines, cease-and-desist orders, civil and criminal penalties or other sanctions.regulatory obligations.
A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s and Regency’s operations and otherwise materially adversely affect their cash flow.
Some of ETP’s and Regency’s operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas pipeline and other facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Virtually all of ETP’s and Regency’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.
If one or more facilities that are owned by ETP or Regency or that deliver natural gas or other products to ETP or Regency are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s or Regency’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s or Regency’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s or Regency’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s or Regency’s cash available for paying distributions to its Unitholders, including us.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP and Regency may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable

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terms, if at all. If ETP or Regency were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s or Regency’s financial position and results of operations, as applicable. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Terrorist attacks aimed at our facilities could adversely affect its business, results of operations, cash flows and financial condition.
The United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on ETP’s or Regency’sSunoco LP’s facilities or pipelines, those of their customers, or in some cases, those of other pipelines could have a material adverse effect on ETP’s or Regency’sSunoco LP’s business, financial condition and results of operations.
Cybersecurity breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personal identification information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruption of our operations, damage to our reputation, and cause a loss of confidence in our products and services, which could adversely affect our business.
Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and other related restrictions arising after the Deepwater Horizon incident in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.
In response to the Deepwater Horizon incident and resulting oil spill in the United States Gulf of Mexico in 2010,recent years, the federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the U.S.United States Department of the Interior, have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. These governmental agencies have implemented and enforced new rules, Notices to Lessees and Operators and temporary drilling moratoria that imposed safety and operational performance measures on exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation of drilling activities. Compliance with these added and more stringent regulatory restrictions in addition torequirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in current decisions and rulings by governmental agencies, and delays in the processing and approval of drilling permits andor exploration, development, and oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance
In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the Gulffuture that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural gas exploration and production operations conducted offshore by certain of MexicoETP’s customers. For example, in April 2016, the BOEM published a proposed rule that would update existing air-emissions requirements relating to offshore oil and asnatural-gas activity on federal Outer Continental Shelf waters. However, in May 2017, Order 3350 was issued by the Department of the Interior Secretary Ryan Zinke, directing the BOEM to reconsider a result, developingnumber of regulatory initiatives governing oil and implementing new,gas exploration in offshore waters, including, among other things, a cessation of all activities to promulgate the April 2016 proposed rulemaking (“Order 3350”). In an unrelated legal initiative, BOEM issued a Notice to Lessees and Operators (“NTL #2016-N01”) that became effective in September 2016 and imposes more restrictive requirements. One example is the 2013 amendmentsstringent requirements relating to the federal Workplace Safety Rule regardingprovision of financial assurance to satisfy decommissioning obligations. Together with a recent re-assessment by BSEE in 2016 in how it determines the utilizationamount of a more comprehensive SEMS, which amended rule is sometimes referred to as SEMS II. A second, and more recent, example isfinancial assurance required, the August 2014 Advanced Notice of Proposed Rulemaking that ultimately seeks to bolster therevised BOEM-administered offshore financial assurance program that is currently being implemented is expected to result in increased amounts of financial assurance being required of operators on the OCS, which amounts may be significant. However, as directed under Order 3350, the BOEM has delayed implementation of NTL #2016-N01 so that it may reconsider this regulatory initiative and, bonding program. Among other adverse impacts, these additional measurescurrently, this NTL’s implementation timeline has been extended indefinitely beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The April 2016 proposed rule and NTL #2016-N01, should they be finalized and/or implemented, as well as any new rules, regulations, or legal initiatives could delay or disrupt our and our customers’customers operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us or out customersour customers’ to incur penalties, fines, or shut-in production. If similarproduction or lease cancellation. Also, if material spill incidentsevents were to occur in the future, the United States or other countries could elect to again issue directives to temporarily cease drilling activities offshore and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration development and production.development. The overall costs imposed on ETP’s customers to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete. We cannot predict with any certainty the full impact of any new laws or regulations on ourETP’s customers’ drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. The occurrence of any one or more of these developments has the potential to adversely impact ourcould result in decreased demand for ETP’s services, which could have a material adverse effect on its business as well as ourits financial position, results of operation and liquidity.

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Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.
The petroleum products that we store and transport through Sunoco Logistics’ETP’s operations are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
In addition, our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.
Our business could be affected adversely by union disputes and strikes or work stoppages by Panhandle’s and Sunoco Inc.’sLP’s unionized employees.
As of December 31, 2014,2017, approximately 6%5% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that Panhandle or Sunoco, Inc. will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.
Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, have a significant impact on our retail marketing business.
Federally mandated standards for use of renewable biofuels, such as ethanol and biodiesel in the production of refined products, are transforming traditional gasoline and diesel markets in North America. These regulatory mandates present production and logistical challenges for both the petroleum refining and ethanol industries, and may require us to incur additional capital expenditures or expenses particularly in our retail marketing business. We may have to enter into arrangements with other parties to meet our obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits. There also will be compliance costs related to these regulations. We may experience a decrease in demand for refined petroleum products due to new federal requirements for increased fleet mileage per gallon or due to replacement of refined petroleum products by renewable fuels. In addition, tax incentives and other subsidies making renewable fuels more competitive with refined petroleum products may reduce refined petroleum product margins and the ability of refined petroleum products to compete with renewable fuels. A structural expansion of production capacity for such renewable biofuels could lead to significant increases in the overall production, and available supply, of gasoline and diesel in markets that we supply. In addition, a significant shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel, or otherwise, also could lead to a decrease in demand, and reduced margins, for the refined petroleum products that we market and sell.
It is possible that any, or a combination, of these occurrences could have a material adverse effect on Sunoco, Inc.’s business or results of operations.
We have outsourced various functions related to our retail marketing business to third-party service providers, which decreases our control over the performance of these functions. Disruptions or delays of our third-party outsourcing partners could result in increased costs, or may adversely affect service levels. Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.
Sunoco, Inc. has previously outsourced various functions related to our retail marketing business to third parties and expects to continue this practice with other functions in the future.
While outsourcing arrangements may lower our cost of operations, they also reduce our direct control over the services rendered. It is uncertain what effect such diminished control will have on the quality or quantity of products delivered or services rendered, on our ability to quickly respond to changing market conditions, or on our ability to ensure compliance with all applicable domestic and foreign laws and regulations. We believe that we conduct appropriate due diligence before entering into agreements with our outsourcing partners. We rely on our outsourcing partners to provide services on a timely and effective basis. Although we continuously monitor the performance of these third parties and maintain contingency plans in case they are unable to perform as

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agreed, we do not ultimately control the performance of our outsourcing partners. Much of our outsourcing takes place in developing countries and, as a result, may be subject to geopolitical uncertainty. The failure of one or more of our third-party outsourcing partners to provide the expected services on a timely basis at the prices we expect, or as required by contract, due to events such as regional economic, business, environmental or political events, information technology system failures, or military actions, could result in significant disruptions and costs to our operations, which could materially adversely affect our business, financial condition, operating results and cash flow.
Our failure to generate significant cost savings from these outsourcing initiatives could adversely affect our profitability and weaken Sunoco, Inc.’s competitive position. Additionally, if the implementation of our outsourcing initiatives is disruptive to our retail marketing business, we could experience transaction errors, processing inefficiencies, and the loss of sales and customers, which could cause our business and results of operations to suffer.
As a result of these outsourcing initiatives, more third parties are involved in processing our retail marketing information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about our retail marketing business or our clients, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss or misuse of this information, result in litigation and potential liability for us, lead to reputational damage to the Sunoco, Inc. brand, increase our compliance costs, or otherwise harm our business.
Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.
Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.
Security
Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.
Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-today operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.
The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results. In addition, the passage of the Health Care Reform Act in 2010 could significantly increase the cost of providing health care benefits for employees.
Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership’s future consolidated financial results. In addition, the passage of the Health Care Reform Act of 2010 could significantly increase the cost of health care benefits for our employees. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Partnership’s regulated businesses, the Partnership’s subsidiaries may not recover all of the costs and those rates are generally not immediately responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.

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Regency’s contract compression operations depend on particular suppliers and is vulnerable to parts and equipment shortages and price increases, which could have a negative impact on its results of operations.
The principal manufacturers of components for Regency’s natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers, and Ariel Corporation for compressors and frames. Regency’s reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. Regency also relies primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble its compression units. Regency does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on Regency’s results of operations and could damage its customer relationships. In addition, since Regency expects any increase in component prices for compression equipment or packaging costs will be passed on to Regency, a significant increase in their pricing could have a negative impact on Regency’s results of operations.
Mergers among Sunoco Logistics’ customers and competitors could result in lower volumes being shipped on itsour pipelines or products stored in or distributed through itsour terminals, or reduced crude oil marketing margins or volumes.
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of Sunoco Logistics’our systems in those markets where the systems compete. As a result, Sunoco Logisticswe could lose some or all of the volumes and associated revenues from these customers and could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.
A portion of Sunoco Logistics’ general and administrative services have been outsourced to third-party service providers. Fraudulent activity or misuse of proprietary data involving its outsourcing partners could expose us to additional liability.
Sunoco Logistics utilizes both affiliate entities and third parties in the processing of its information and data. Breaches of its security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about Sunoco Logistics or its customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose Sunoco Logistics to a risk of loss or misuse of this information, result in litigation and potential liability for Sunoco Logistics, lead to reputational damage, increase compliance costs, or otherwise harm its business.
A material decrease in demand or distribution of crude oil available for transport through Sunoco Logistics’ pipelines or terminal facilities could materially and adversely affect our results of operations, financial position, or cash flows.
The volume of crude oil transported through Sunoco Logistics’ crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by its assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to Sunoco Logistics’ customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in Sunoco Logistics’ crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all. If Sunoco Logistics is unable to replace any significant volume declines with additional volumes from other sources, our results of operations, financial position, or cash flows could be materially and adversely affected.
LCLliquefaction project is dependent upon securing long-term contractual arrangements for the off-take of LNG on project financingterms sufficient to fundsupport the costs necessary to constructfinancial viability of the liquefaction project. If project financing is unavailable to supply the funding necessary to complete the liquefaction project, LCL may not be able to secure alternative funding and FID may not be achieved.
LCL, an entity whose parent is owned 60% by ETE and 40% by ETP, is in the process of developing a proposed liquefaction project at the site of ETE’s existing regasification facility in conjunctionLake Charles, Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc (“BG”(now "Shell") pursuant to a project development agreement entered into in September 2013. Pursuantrelated to this agreement, eachproject expired in February 2017. On June 28, 2017, LCL signed a memorandum of LCLunderstanding with Korea Gas Corporation and BG are obligatedShell to pay 50%study the feasibility of a joint development of the development expensesLake Charles liquefaction project. The project would utilize existing dock and storage facilities owned by ETE located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the liquefaction project, subject to reimbursement byoff-take of LNG which in turn will be dependent upon supply and demand factors affecting the other party if such party withdraws fromprice of LNG in foreign markets. The financial viability of the project prior to both parties making a final investment decision (“FID”) to become irrevocably obligated to fully develop the project, subject to certain exceptions. Through December 31, 2014, LCL had incurred $75 million of development costs associated with the liquefaction project that were funded by ETE and ETP, and ETE and ETP have indicated that they intend to provide the funding necessary for the remaining development costs, but they have no obligation to do so. If ETE and ETP are unwilling or unable to provide funding to LCL for its share of the remaining development costs, or if BG is unwilling or unable to provide funding for its share of the remaining development costs, the liquefaction project couldwill also be delayed or cancelled.

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The liquefaction project is subject to the right of each of LCL and BG to withdraw from the project in its sole discretion at any time prior to an affirmative FID.
The project development agreement provides that either LCL or BG may withdraw from the liquefaction project at any time prior to each party making an affirmative FID. LCL’s determination of whether to reach an affirmative FID is expected to be baseddependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the expected revenue to be generated by LCL pursuant to the terms of the liquefaction services agreement anticipated to be entered into between LCL and BG in connection with both parties reaching an affirmative FID, and the terms and conditions of the financing for the construction of the liquefaction facility. BG’s determination of whether to reach an affirmative FID is expected be based on a number of factors, includingfacility, the expected tolling charges it would be required to pay under the termscost of the liquefaction services agreement, the costs anticipated to be incurred by BG to purchase natural gas for delivery to the liquefaction facility,supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia) over the expected 25-year term.  Some of the liquefaction services agreement. As the tolling charges payable to LCL under the liquefaction services agreement are anticipated to be based on a rate of return formula tied to the construction costs for the liquefaction facility, these costs are anticipated to also have a significant bearing with respect to BG’s determination whether to reach an affirmative FID. As these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the price of LNG in foreign markets, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that both LCL and BGthe parties will reach an affirmative FIDdetermine to construct the liquefaction facility.proceed to develop this project.

The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or revocation.
The liquefaction project remains subject to (i) the receipt of approval by the FERC to construct and operate the facilities, (ii) approvals and permits from the U.S. Army Corps of Engineers (“USACE”) for wetlands mitigation and permanent and temporary marine dock modifications and dredging at the Lake Charles LNG facility and (iii) other governmental and regulatory approvals and permits, including air permits under the Clean Air Act. Furthermore, while a subsidiary of BGWhile LCL has received authorization from the DOE to export LNG to non-FTA countries, the non-FTA authorization is subject to review, and the DOE may impose additional approval and permit requirements in the future or revoke the non-FTA authorization should the DOE conclude that such export authorization is inconsistent with the public interest.  Certain of the permits and approvals must be obtained before construction on the liquefaction project can begin and are still under review by state and federal authorities. We do not know whether or when any such approvals or permits can be obtained, or whether any existing or potential interventions or other actions by third parties will interfere with its ability to obtain and maintain such permits or approvals. The failure by LCL to timely receive and maintain the remaining approvals necessary to complete and operate the liquefaction project could have a material adverse effect on its operations and financial condition.
Sunoco LP is subject to federal laws related to the Renewable Fuel Standard.
New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make additional capital expenditures or incur additional liabilities. For example, certain independent refiners have initiated discussions with the EPA to change the way the Renewable Fuel Standard (RFS) is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers are obligated to obtain renewable identification numbers (“RINS”) either by blending biofuel into gasoline or through purchase in the open market. If the obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have to utilize the RINS it obtains through its blending activities to satisfy a new obligation and would be unable to sell RINS to other obligated parties, which may cause an impact on the fuel margins associated with Sunoco LP’s sale of gasoline.
The occurrence of any of the events described above could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
Sunoco LP is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers.
Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities, including commodities that Sunoco LP distributes. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce Sunoco LP’s ability to procure product, require it to incur additional handling costs and/or require the expenditure of capital. If Sunoco LP is unable to procure product or recover these costs through increased selling price, it may not be able to meet its financial obligations. Failure to comply with these regulations could result in substantial penalties for Sunoco LP.
The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements.
Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of corporations that are subject to all of the corporate governance requirements of the applicable stock exchange.
Tax Risks to Common Unitholders
Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us, ETP or RegencySunoco LP as a corporation for federal income tax purposes or if we, ETP or RegencySunoco LP become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investments in ETP and Regency dependsSunoco LP depend largely on ETP and RegencySunoco LP being treated as partnerships for federal income tax purposes.
Despite the fact that we, ETP and RegencySunoco LP are each a limited partnership under Delaware law, we would each be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we, ETP and RegencySunoco LP satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us, ETP or RegencySunoco LP to be treated as a corporation for federal income tax purposes or otherwise subject us ETP or Regency to taxation as an entity.
If we, ETP or RegencySunoco LP were treated as a corporation, we would pay federal income tax on our taxable income at the corporate tax rate which is currently a maximum of 35%, and we would likely pay additional state income taxes at varying rates. Distributions to Unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to Unitholders. Because a tax would then be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Therefore,

treatment of us as a corporation would result in a material

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reduction in the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of our Common Units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our Unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or to additional taxation as an entity for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our case available for distribution to our unitholders.
The tax treatment of publicly traded partnerships or an investment in ETP or Regency’s commonour units could be subject to potential legislative, judicial or administrative changes andor differing interpretations, possibly applied on a retroactive basis.
The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in ETP or Regency’sour common units may be modified by administrative, legislative or judicial or administrative changes andor differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider substantive changes to the existing United States federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’sAlthough there is no current legislative proposal, or other similar proposals could eliminatea prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our ETP’s and Regency’s treatment as a partnership for U.S.United States federal income tax purposes. Any
In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for United States federal income tax purposes.
However, any modification to the U.S.United States federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S.United States federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any suchsimilar or future legislative changes could negatively impact the value of an investment in our common units.
The You are urged to consult with your own tax treatmentadvisor with respect to the status of Sunoco Logistics dependsregulatory or administrative developments and proposals and their potential effect on its status as a partnership for federal income tax purposes, as well as its not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat Sunoco Logistics as a corporation for federal income tax purposes or if it were to become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to its unitholders.
The anticipated after-tax economic benefit of ouryour investment in the common units of Sunoco Logistics depends largely on Sunoco Logistics being treated as a partnership for federal income tax purposes. Sunoco Logistics has not requested, and does not plan to request, a ruling from the IRS on this matter. The IRS may adopt positions that differ from the ones Sunoco Logistics has taken. A successful IRS contest of the federal income tax positions Sunoco Logistics takes may impact adversely the market for its common units, and the costs of any IRS contest will reduce Sunoco Logistics’ cash available for distribution to its unitholders. If Sunoco Logistics were to be treated as a corporation for federal income tax purposes, it would pay federal income tax at the corporate tax rate, and likely would pay state income tax at varying rates. Distributions to its unitholders generally would be subject to tax again as corporate distributions. Treatment of Sunoco Logistics as a corporation would result in a material reduction in its anticipated cash flow and after-tax return to its unitholders. Current law may change so as to cause Sunoco Logistics to be treated as a corporation for federal income tax purposes or to otherwise subject it to a material amount of entity-level taxation. States are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. If any states were to impose a tax on Sunoco Logistics, the cash available for distribution to its unitholders would be reduced.
As discussed above, the present federal income tax treatment of publicly traded partnerships, including Sunoco Logistics, or our investment in its common units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for Sunoco Logistics to meet the exception which allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause Sunoco Logistics to change its business activities, or affect the tax consequences of our investment in Sunoco Logistics’ common units. Any such changes could negatively impact the value of our investment in Sunoco Logistics’ common units.
If the IRS contests the federal income tax positions we or our subsidiaries take, the market for our Common Units, ETP Common Units or Regency Common Units may be adversely affected and the costs of any such contest will reduce cash available for distributions to our Unitholders.
Neither we nor our subsidiariesWe have not requested a ruling from the IRS with respect to our treatment as partnershipsa partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we or our subsidiaries take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we or our subsidiaries take. A court may not agree with some or all of the positions we or our subsidiaries take. Any contest with the IRS may materially and adversely impact the

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market for our Common Units, ETP’s Common Units or Regency’s Common Units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us or our subsidiaries, and therefore indirectly by us, as a Unitholder and as the owner of the general partner of interests in ETP and Regency, reducing the cash available for distribution to our Unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our Unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each Unitholder and former Unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our Unitholders and former Unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current Unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such Unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our Unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
UnitholdersBecause our unitholders will be treated as partners to whom we will allocate taxable income which will be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. UnitholdersOur unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that resultsresult from the taxation of their share of our taxablethat income.
Tax gain or loss on disposition of our Common Units could be more or less than expected.
If Unitholdersour unitholders sell their Common Units,common units, they will recognize a gain or loss equal to the difference between the amount realized and thetheir tax basis in those Common Units. Becausecommon units. Prior distributions to our unitholders in excess of the Unitholder’s allocable share of ourtotal net taxable income result inthe unitholder was allocated for a decrease in the Unitholder’sunit, which decreased their tax basis in their Common Units, the amount, if any, of such prior excess distributions with respect to the units soldthat unit, will, in effect, become taxable income to our unitholders if the Unitholder if they sell such unitscommon unit is sold at a price greater than their adjusted tax basis in those units,that common unit, even if the price receivedthey receive is less than their original cost. Furthermore, aA substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions and certain other items.income. In addition, because the amount realized includes a Unitholder’s share ofif our nonrecourse liabilities, if a Unitholder sellsunitholders sell their units, the Unitholdersthey may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning Common Unitsour units that may result in adverse tax consequences to them.
Investment in Common Unitsour units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to Unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be “unrelated business taxable income” and will be taxable to them. Allocations and/Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or distributions to non-U.S. persons will be reducedbusiness (including by withholding taxes, imposed at the highest effective tax rate applicable to non-U.S. persons, and each non-U.S. person will beattribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to file United States federalcompute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and state income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or non-U.S. person, youvice versa. Tax-exempt entities should consult youra tax advisor before investing in our commonunits.
Non-United States Unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.
Non-United States unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a United States trade or business.  As a result, distributions to a Non-United States unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-United States unitholder who sells or otherwise disposes of a unit will also be subject to United States federal income tax on the gain realized from the sale or disposition of that unit. 
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-United States unitholder’s sale or exchange of an interest in a partnership that is engaged in a United States trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges.  It is not clear if or when such regulations or other guidance will be issued.  Non-United States unitholders should consult a tax advisor before investing in our units.
We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
Even though we (as a partnership for U.S.United States federal income tax purposes) are not subject to U.S.United States federal income tax, some of our operations are conducted through subsidiaries that are organized as corporations for U.S.United States federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for U.S.United States federal income tax purposes, is subject to corporate-level U.S.United States federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the Common Units.
Because we cannot match transferors and transferees of Common Units and because of other reasons, we will adopthave adopted depreciation, depletion and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units and could have a negative impact on the value of our Common Units or result in audit adjustments to tax returns of our Unitholders. Moreover, because we have subsidiaries that are organized as C corporations for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having a greater tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our Unitholders.

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We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which couldaspects of our proration method, and if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. The useSimilarly, we generally allocate certain deductions for depreciation of this proration method may not be permitted under existing Treasury Regulations. Recently, however,capital additions, gain or loss realized on a sale or other disposition of our assets and, in the Departmentdiscretion of the Treasury andgeneral partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the IRS issued proposedAllocation Date. Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may useallow a similar monthly simplifying convention, to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposedbut such regulations do not specifically authorize the useall aspects of the proration method we have adopted. If the IRS were to challenge our proration method, or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.Unitholders.
A Unitholder whose units are the subject of a securities loan (e.g. a loan to a “short seller”) to cover a short sale of units may be considered as having disposed of those units. If so, the Unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a Unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the Unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the Unitholder and any cash distributions received by the Unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
ETP and RegencyWe have adopted certain valuation methodologies in determining unitholder’sUnitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of ETP’sour common units.
When we issue additional units or Regency’s Common Units and our Common Units.
In determining the items of income, gain, loss and deduction allocable to our, ETP’s or Regency’s unitholders,engage in certain other transactions, we must routinely determine the fair market value of our respective assets.assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our ETP’s or Regency’s common units as a means to measure the fair market value of our respectiveassets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge theseour valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and the resultingintangible assets, and allocations of income, gain, loss and deduction.deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount character, and timing of taxable income or loss being allocated to our Unitholders, the ETP Unitholders or the Regency Unitholders.unitholders. It also could affect the amount of gain on the sale of Common Unitscommon units by our Unitholders, ETP’s Unitholders or Regency’s Unitholdersunitholders and could have a negative impact on the value of our Common Units or those of ETP or Regencycommon units or result in audit adjustments to the tax returns of our ETP’s or Regency’s Unitholdersunitholders without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit during the applicable twelve-month period will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all Unitholders which would require us to file two federal partnership tax returns (and our Unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year, and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a Unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such Unitholder’s taxable income for the year of termination. A technical termination currently would not affect our classification as a partnership for federal income tax purposes. We would be treated as a new partnership for tax purposes on the technical termination date, and would be required to make new tax elections and could be subject to penalties if we were unable to determine in a timely manner that a termination occurred. The IRS has recently announced a relief procedure whereby a publicly traded partnership that has technically terminated may be permitted to provide only a single Schedule K-1 to unitholders for the two tax years within the fiscal year in which the termination occurs.

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Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our Common Units.units.
In addition to federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we ETP or Regencyour subsidiaries conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. We currently own property or conduct business in many states, most of which impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns.
Risks Related to ETP’s Pending Acquisition of Regency
The completion of the Regency Merger is subject to the satisfaction of certain conditions to closing, and the date that the Regency Merger would be consummated is uncertain.
The completion of the Regency Merger is subject to the absence of a material adverse change to the business or results of operation of ETP and Regency, the receipt of necessary regulatory approvals, the approval of the Regency Merger by a majority of the outstanding Regency common units and the satisfaction or waiver of other conditions specified in the merger agreement related to the Regency transaction. In the event those conditions to closing are not satisfied or waived, we would not complete the Regency Merger.
While ETP expects to complete the Regency Merger in the second quarter of 2015, the completion date of the Regency Merger might be later than expected due to delays in obtaining required regulatory approvals or other unforeseen events.
Failure to complete the merger, or significant delays in completing the merger, could negatively affect the trading price of our common units and our future business and financial results.
Completion of the merger is not assured and is subject to risks, including the risks that approval of the merger by Regency’s unitholders or governmental agencies is not obtained or that other closing conditions are not satisfied. If the merger is not completed, or if there are significant delays in completing the merger, it could negatively affect the trading price of ETP’s common units and ETP’s future business and financial results, and ETP willUnitholders may be subject to several risks, including the following:
liability for damages under the terms and conditions of the merger agreement;
negative reactions from the financial markets, including declines in the price of ETP’s common units due to the fact that current prices may reflect a market assumption that the merger will be completed; and
the attention of ETP’s management will have been diverted to the merger rather than its own operations and pursuit of other opportunities that could have been beneficial to ETP.
ETP may have difficulty attracting, motivating and retaining executives and other employees in light of the merger.
Uncertainty about the effect of the mergerlimitation on ETP’s employees may have an adverse effect on us and the combined organization. This uncertainty may impair ETP’s ability to attract, retain and motivate personnel until the merger is completed. Employee retention may be particularly challenging during the pendency of the merger, as employees may feel uncertain about their future roles with the combined organization. In addition, ETP may have to provide additional compensation in order to retain employees. If ETP’s employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined organization, the ability of ETP to realize the anticipated benefits of the merger could be reduced. Also, if ETP fails to complete the merger, it may be difficult and expensive to recruit and hire replacements for such employees.
Regency is subject to contractual restrictions while the merger is pending, which could materially and adversely affect each party’s business and operations, and, pending the completion of the transaction, our business and operations could be materially and adversely affected.
Under the terms of the Regency Merger agreement, Regency is subject to certain restrictions on the conduct of business prior to completing the transaction, which may adversely affect their ability to executededuct interest expense incurred by us.
In general, our unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. Although the interest limitation does not apply to certain business strategies without first obtaining consent from ETP, including their abilityregulated pipeline businesses, application of the interest limitation to tiered businesses like ours that hold interests in certain casesregulated and unregulated businesses is not clear. Pending further guidance specific to enter into contracts, incur capital expenditures or grow its business. The merger agreement also restricts Regency’sthis issue, we have not yet determined the impact the limitation could have on our unitholders’ ability to solicit, initiate or encourage alternative acquisition proposals with any third party and may deter a potential acquirer from proposing an alternative transaction or may limitdeduct our ability to pursue any such proposal. Such limitations could negatively affect our business and operations prior to the completion of the proposed transaction.

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Furthermore, the process of planning to integrate two businesses and organizations for the post-merger period can divert management attention and resources and could ultimately have an adverse effect on us.
In connection with the pending merger,interest expense, but it is possible that some customers, suppliers and other persons with whom Regency has business relationships may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationship as a result of the transaction, which could negatively affect our revenues, earnings and cash flows, as well as the market price of our common units, regardless of whether the transaction is completed.
Lawsuits have been filed against ETP, ETP GP, Regency, Regency GP LP, Regency GP LP’s board of directors, and ETE challenging the merger, and any injunctive relief or adverse judgment for monetary damages could prevent the merger from occurring or could have a material adverse effect on us following the merger.
ETP, ETP GP, Regency, Regency GP LP, the directors of the Regency GP LP, and ETE are named defendants in purported class actions and derivative petitions brought by purported Regency unitholders in Dallas County, Texas, generally alleging claims of breach of duties under the partnership agreement, breach of the implied covenant of good faith and fair dealing in connection with the merger transactions, and aiding and abetting arising out of the defendants’ pursuit of the merger by way of an allegedly conflicted and unfair process. Similar lawsuits have been filed in the United States District Court for the Northern District of Texas. The plaintiffs in these lawsuits seek to enjoin the defendants from proceeding with or consummating the merger and, to the extent that the merger is implemented before relief is granted, plaintiffs seek to have the merger rescinded. Plaintiffs also seek money damages and attorneys’ fees. One of the conditions to the completion of the merger is that no order, decree, or injunction of any court or agency of competent jurisdiction shall be in effect, and no law shall have been enacted or adopted, that enjoins, prohibits, or makes illegal consummation of any of the transactions contemplated by the merger agreement. A preliminary injunction could delay or jeopardize the completion of the merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the merger. An adverse judgment for rescission or for monetary damages could have a material adverse effect on us following the merger.
ETP will incur substantial transaction-related costs in connection with the merger.
ETP expects to incur a number of non-recurring merger-related costs associated with completing the merger, combining the operations of the two companies, and achieving desired synergies. These fees and costsunitholders’ interest expense deduction will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to legal, financial and accounting advisors, filing fees and printing costs. Additional unanticipated costs may be incurred in the integration of Regency and ETP’s businesses. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time. Thus, any net benefit may not be achieved in the near term, the long term or at all.limited.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
A description of our properties is included in “Item 1. Business.” In addition, we andown office buildings for our subsidiaries own an executive office buildingoffices in Dallas, Texas and office buildings in Newton Square, Pennsylvania and Houston, Corpus Christi and San Antonio, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.
Substantially all of our subsidiaries’ pipelines, which are described in “Item 1. Business”Business,” are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. Our subsidiaries have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our

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subsidiaries’ pipelines were built were purchased in fee. ETP also owns and operates multiple natural gas and NGL storage facilities and owns or leases other processing, treating and conditioning facilities in connection with its midstream operations.
ITEM 3. LEGAL PROCEEDINGS
Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other refiners, manufacturers and sellersmembers of gasoline, is a defendantthe petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, typically include water purveyors and municipalities responsible for supplying drinking water andstate-level governmental authorities. The plaintiffs are asserting primarilyentities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, andand/or deceptive business practices. The plaintiffs in all of the cases are seekingseek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2014,2017, Sunoco, Inc. is a defendant in fiveseven cases, including casesone case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two others by the Commonwealth of Puerto Rico with theRico.

The more recent Puerto Rico action beingis a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are venuedpending in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico,court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and Pennsylvania cases assert natural resource damage claims.one is pending in state court in Maryland.
Fact discovery has concludedSunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with respect to an initial setthe State of 19 sites each that will beNew Jersey. The Court approved the subjectJudicial Consent Order on December 5, 2017. Dismissal of the first trial phase in the New Jersey case and the initial Puerto Rico case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability ofagainst Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in these matters. December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized;realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that anAn adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any saidsuch adverse determination occurs, but does not believe that any such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
In January 2012, Sunoco LogisticsETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which Sunoco LogisticsETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. Sunoco LogisticsThis PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order ofon Consent with the EPA have been fulfilled and the Order has been satisfied and closed. Sunoco LogisticsETP has also received a "No“No Further Action"Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. Sunoco Logistics has notIn May 2016, ETP received anya proposed penaltiespenalty from the EPA and DOJ associated with this release, and continues to cooperate with both PHMSA and the EPA to complete the investigation of the incident and repair of the pipeline.
In 2012, the EPA issued a proposed consent agreement related to the releases that occurred at Sunoco Logistics’ pump station/tank farm in Barbers Hill, Texas and pump station/tank farm located in Cromwell, Oklahoma in 2010 and 2011, respectively. These matters were referred to the U.S. Department of Justice (“DOJ”) by the EPA. In November 2012, Sunoco Logistics received an initial assessment of $1.4 million associated with these releases. Sunoco Logistics is in discussionswork with the EPA and the DOJ oninvolved parties to bring this matter and hopes to resolve the issue during 2015.closure. The timing orand outcome of this matter cannot be reasonably determined at this time; however, Sunoco Logisticstime. However, ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In September 2013,October 2016, the Pennsylvania Department of Environmental Protection (“PADEP”)PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penaltiespenalty is in excess of $0.1 million based on alleged violations of various safety regulations relating$100,000. The case went to the November 2008 products release by Sunoco Pipeline L.P., a subsidiary of Sunoco Logistics,hearing in Murrysville, Pennsylvania. Sunoco Logistics is currently in discussionsMarch 2017 and remains open with the PADEP. The timing or outcome of this matter cannot be reasonably determined at this time. However, Sunoco LogisticsPHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In November 2014,April 2016, the PADEPPHMSA issued a NoticeNOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of Violation andETP’s Permian Express 2 pipeline system in Texas.  The proposed penalties potentiallyare in excess of $100,000 relating$100,000. The case went to unpermitted wetlandshearing in November 2016 and streams along the second phase of construction of the Canton Pipeline Project by Regency Marcellus Gas Gathering LLC (“Regency Marcellus”), a subsidiary of Regency. Regency Marcellus has submitted amended permit applications for this phase of construction and is working the PADEP to acquire amended permits for the proposed crossings of the wetland resources. Regency Marcellus is in discussionsremains open with the PADEP regarding the aforementioned Notice of Violation. The timing of outcome of this matter cannot reasonably be determined at this time, however we doPHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our business orcrude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations.operations, cash flows, or financial position.
In November 2013,August 2017, the DOTPHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In December 2016, we received multiple Notice of ViolationViolations (“NOVs”) from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at our Marcus Hook Industrial Complex (“MHIC”) in July 2016. We also entered in a Consent Order and proposedAgreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to our tank inspection plan at MHIC.  These actions propose penalties in excess of $0.1 million based on alleged violations of various safety regulations relating to the February 2012 products release by FGT in Baton Rouge, Louisiana. ETP received an initial assessment of $0.2 million associated with this release. ETP is$100,000, and we are currently in discussions with the DOT on this matterPADEP and

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hopes DELCORA to resolve this issue in 2015.these matters. The timing or outcome of this matterthese matters cannot be reasonably determined at this time. However,time; however, we do not expect there to be a material impact to our results of operations, cash flows, or financial position.
The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of the Rover pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April 2017 to July 2017. Although Rover has successfully completed clean-up mitigation for the alleged violations to Ohio EPA’s satisfaction, the Ohio EPA has proposed penalties of approximately $2.6 million in connection with the alleged violations and is seeking certain injunctive relief. The Ohio Attorney General filed a complaint in the Court of Common Pleas of Stark County, Ohio to obtain these remedies and that case remains pending and is in the early stages. The timing or outcome of this matter cannot be reasonably

determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. In response, FERC authorized Rover to resume HDD activities at certain sites. On January 24, 2018, FERC ordered Rover to cease HDD activities at the Tuscarawas River HDD site pending FERC review of additional information from Rover. Rover continues to correspond with regulators regarding drilling operations and drilling plans at the HDD sites where Rover has not yet completed HDD activities, including the Tuscarawas River HDD site. The timing or around December 24, 2014,outcome of this matter cannot be reasonably determined at this time. We do not expect there to be a material impact to its results of operations, cash flows or financial position.
In late 2016, FERC Enforcement Staff began a non-public investigation of Rover’s demolition of the Stoneman House, a potential historic structure, in connection with Rover’s application for permission to construct a new interstate natural gas pipeline and related facilities.  Rover and ETP are cooperating with the investigation.  In March and April 2017, Enforcement Staff provided Rover its non-public preliminary findings regarding its investigation.  The company disagrees with those findings and intends to vigorously defend against any potential penalty. Given the stage of the proceeding, and the non-public nature of the preliminary findings and investigation, ETP is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.
On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project.  The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”).  On August 10, 2017 the parties reached a final settlement requiring that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation.  Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits.  Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.
In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project.  Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval.  SPLP is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
On January 18, 2018, PHMSA issued toa NOPV and a Proposed Civil Penalty in connection with alleged violations on ETP’s Panhandle a Notice of Proposed Safety Order (the “Notice”) regarding the ETP\PEPLEast Boston jet fuel pipeline system.in Boston, MA. The Notice stated that PHMSA had initiated an investigation of the safety of the ETP/PEPL pipeline system and specifically referenced two incidents: 1) a November 28, 2013, incident on ETP/PEPL’s 400 line approximately 4.7 miles downstream of the Houstonia compressor station near Hughesville, Missouri, and 2) an October 13, 2014, failure on the ETP/PEPL 100 line near Centerview, Missouri. The Notice further mentioned other incidents on the ETP/PEPL pipeline system that PHMSA claims to have addressed with ETP/PEPL.  The Notice also stated that “[a]s a result of [PHMSA’s] investigation, it appears that conditions exist on the ETP/PEPL pipeline system that pose a pipeline integrity risk to public safety, property or the environment.”  ETP/PEPL is fully cooperatingcase remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its investigation.results of operations, cash flows or financial position.
On January 18, PHMSA issued a NOPV and a PCO in connection with alleged violations on Eastern Area refined products and crude oil pipeline system in the States of MI, OH, PA, NY, NJ and DE. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed above were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report environmental governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $0.1 million.$100,000.
For a description of other legal proceedings, see Note 1211 to our consolidated financial statements.statements included in “Item 8. Financial Statements and Supplementary Data.”
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

PART II
ITEM 5.  MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Parent Company
Market Price of and Distributions on Common Units and Related Unitholder Matters
The Parent Company’s common units are listed on the NYSE under the symbol “ETE.” The following table sets forth, for the periods indicated, the high and low sales prices per ETE Common Unit, as reported on the NYSE Composite Tape, and the amount of cash distributions paid per ETE Common Unit for the periods indicated.
Price Range (1)
 
Cash
Distribution (2)
Price Range 
Cash
Distribution (1)
High Low High Low 
Fiscal Year 2014:     
Fiscal Year 2017:     
Fourth Quarter$66.21
 $45.88
 $0.4500
$18.71
 $15.64
 $0.3050
Third Quarter63.53
 53.17
 0.4150
18.50
 16.18
 0.2950
Second Quarter60.58
 46.04
 0.3800
19.82
 15.03
 0.2850
First Quarter43.11
 38.99
 0.3588
20.05
 17.62
 0.2850
          
Fiscal Year 2013:     
Fiscal Year 2016:     
Fourth Quarter$42.58
 $32.01
 $0.3463
$19.99
 $13.77
 $0.2850
Third Quarter34.20
 29.47
 0.3363
19.44
 13.45
 0.2850
Second Quarter31.25
 26.56
 0.3275
15.13
 6.40
 0.2850
First Quarter29.54
 23.04
 0.3225
14.39
 4.00
 0.2850

(1)
Prices and distributions have been adjusted to reflect the effect of the two-for-one split of ETE Common Units completed on January 27, 2014. See Note 9 to our consolidated financial statements.
(2) 
Distributions are shown in the quarter with respect to which they relate. For each of the indicated quarters for which distributions have been made, an identical per unit cash distribution was paid on any units subordinated to our Common Units outstanding at such time. Please see “Cash Distribution Policy” below for a discussion of our policy regarding the payment of distributions.

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Description of Units
As of February 18, 2015,16, 2018, there were approximately 129,213158,922 individual common unitholders, which includes common units held in street name. Common units represent limited partner interest in us that entitle the holders to the rights and privileges specified in the Parent Company’s Third Amended and Restated Agreement of Limited Partnership, as amended to date (the “Partnership Agreement”).
As of December 31, 20142017, limited partners ownsown an aggregate 99.7%94.4% limited partner interest in us. Our General Partner owns an aggregate 0.3%0.2% General Partner interest in us. Our common units are registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and are listed for trading on the NYSE. Each holder of a common unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all common units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The common units are entitled to distributions of Available Cash as described below under “Cash Distribution Policy.”
On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on

a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.
The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 2017.
Cash Distribution Policy
General.  The Parent Company will distribute all of its “Available Cash” to its unitholders and its General Partner within 50 days following the end of each fiscal quarter.
Definition of Available Cash.  Available Cash is defined in the Parent Company’s Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:
provide for the proper conduct of its business;
comply with applicable law and/or debt instrument or other agreement; and
provide funds for distributions to unitholders and its General Partner in respect of any one or more of the next four quarters.
The total amount of distributions declared is reflected in Note 9 to our consolidated financial statements.
Recent Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
No repurchases were made duringNone.
Securities Authorized for Issuance Under Equity Compensation Plans
For information on the fourth quartersecurities authorized for issuance under ETE’s equity compensation plans, see “Item 12. Security Ownership of 2014.Certain Beneficial Owners and Management and Related Unitholder Matters.”

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ITEM 6.  SELECTED FINANCIAL DATA
The selected historical financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in millions.
As discussed in Note 2 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data,” in the fourth quarter of 2017, ETP changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories were changed from last-in, first-out (“LIFO”) method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

Years Ended December 31,Years Ended December 31,
2014 2013 2012 2011 20102017 2016* 2015* 2014* 2013*
Statement of Operations Data:                  
Total revenues$55,691
 $48,335
 $16,964
 $8,190
 $6,556
$40,523
 $31,792
 $36,096
 $54,435
 $48,335
Operating income2,470
 1,551
 1,360
 1,237
 1,044
2,713
 1,843
 2,287
 2,389
 1,587
Income from continuing operations1,060
 282
 1,383
 531
 345
2,543
 462
 1,023
 1,014
 318
Income (loss) from discontinued operations(177) (462) 38
 60
 33
Net Income2,366
 —
 1,061
 1,010
 351
Basic income from continuing operations per limited partner unit1.15
 0.33
 0.59
 0.69
 0.44
0.86
 0.95
 1.11
 0.57
 0.17
Diluted income from continuing operations per limited partner unit1.14
 0.33
 0.59
 0.69
 0.44
0.84
 0.93
 1.11
 0.57
 0.17
Cash distribution per unit1.60
 1.33
 1.26
 1.22
 1.08
Basic income (loss) from discontinued operations per limited partner unit(0.01) (0.01) —
 0.01
 0.01
Diluted income (loss) from discontinued operations per limited partner unit(0.01) (0.01) —
 0.01
 0.01
Cash distribution per common unit1.17
 1.14
 1.08
 0.80
 0.67
Balance Sheet Data (at period end):                  
Total assets64,469
 50,330
 48,904
 20,897
 17,379
Assets held for sale3,313
 3,588
 3,681
 3,372
 —
Total assets(1)
86,246
 78,925
 71,144
 64,266
 50,367
Liabilities associated with assets held for sale75
 48
 42
 47
 —
Long-term debt, less current maturities29,653
 22,562
 21,440
 10,947
 9,346
43,671
 42,608
 36,837
 29,477
 22,562
Total equity22,314
 16,279
 16,350
 7,388
 6,248
29,980
 22,431
 23,553
 22,301
 16,341
*As adjusted for the change in accounting policy related to inventory valuation, as discussed above.
(1)
Includes assets held for sale
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts, except per unit data, are in millions)
Energy Transfer Equity, L.P. is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ETE.” ETE was formed in September 2002 and completed its initial public offering in February 2006.
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Regency, Regency GP, Regency LLC, Panhandle, (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco, Inc., Sunoco Logistics, Sunoco LP Susser and ETP Holdco.Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
In 2014, our consolidated subsidiaries, Trunkline LNG Company, LLC, Trunkline LNG Export, LLC and Susser Petroleum Partners LP, changed their names to Lake Charles LNG Company, LLC, Lake Charles LNG Export, LLC and Sunoco LP, respectively. All references to these subsidiaries throughout this document reflect the new names of those subsidiaries, regardless of whether the disclosure relates to periods or events prior to the dates of the name changes.

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OVERVIEW
Energy Transfer Equity, L.P. directly and indirectly owns equity interests in ETP and Regency,Sunoco LP, both publicly traded master limited partnerships engaged in diversified energy-related services.
The historical common units for ETP presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger, discussed in “Item 1. Business.”
At December 31, 2014,January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and RegencySunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as the following:approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.
 ETP Regency
Units held by wholly-owned subsidiaries:   
Common units30.8 57.2
ETP Class H units50.2 —
Units held by less than wholly-owned subsidiaries:   
Common units— 31.4
Regency Class F units— 6.3

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency,Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and the Partnership’s ownership of Lake Charles LNG. The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses, debt service requirements and at ETE’s election, capital contributions to ETP and RegencySunoco LP in respect of ETE’s general partner interests in ETP and Regency.Sunoco LP. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries.
In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.
General
Our primary objective is to increase the level of our distributable cash flow to our unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and liquids businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.
As a result of the Lake Charles LNG Transaction in 2014, ourOur reportable segments were re-evaluated and currently reflect the following reportable segments:are as follows:
•Investment in ETP, including the consolidated operations of ETP;
Investment in Regency,Sunoco LP, including the consolidated operations of Regency;Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
Each of the respective general partners of ETP and RegencySunoco LP have separate operating management and boards of directors. We control ETP and RegencySunoco LP through our ownership of their respective general partners.
Recent Developments
Regency MergerETE Senior Notes Offering
In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.
Sunoco LP Series A Preferred Units
On March 30, 2017, the Partnership purchased 12 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units was 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate would become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference.
In January 2015,2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.
ETE January 2017 Private Placement and ETP and RegencyUnit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units.
January 2018 Sunoco LP Common Units Repurchase
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.

CDM Contribution Agreement
In January 2018, ETP entered into a definitive mergercontribution agreement as amended on February 18, 2015 (the “Merger(“CDM Contribution Agreement”), with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, Regencyamong other things, ETP will mergecontribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a wholly-owned subsidiaryvalue of ETP,approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with Regency continuing as the surviving entitya value of approximately $112 million and becoming a wholly-owned subsidiary of ETP (the “Regency Merger”). At the effective time of the Regency Merger (the “Effective Time”), each Regency common unit and Class F unit will be converted into the right to receive 0.4066 ETP Common Units, plus a number of additional ETP Common Units(iii) an amount in cash equal to $0.32 per Regency common unit divided by the lesser of (i) the volume weighted average price of$1.225 billion, subject to certain adjustments. The Class B Units that ETP Common Units for the five trading days ending on the third trading day

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immediately preceding the Effective Time and (ii) the closing price of ETP Common Units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Regency series A preferred unitwill receive will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. The transaction is subject to other customary closing conditions including approval by Regency’s unitholders.
In addition, ETE, which owns the general partner and 100%partnership interests of USAC that will have substantially all of the incentive distribution rights and obligations of both Regency and ETP, has agreeda USAC Common Unit, except the Class B Units will not participate in distributions made prior to reduce the incentive distributions it receives from ETP by a totalone year anniversary of $320 million over a five year period. The IDR subsidythe closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will be $80 million in the first year post closing and $60 million per year for the following four years.automatically convert into one USAC Common Unit. The transaction is expected to close in the second quarterfirst half of 2015.2018, subject to customary closing conditions.
Bakken Pipeline TransactionIn connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million.
ETP Credit Facilities
On December 1, 2017 ETP entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).
ETP Series A and Series B Preferred Units
In December 2014,November 2017, ETP issued 950,000 of its 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit, and ETE announced550,000 of its 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit.
Distributions on the final termsETP Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a transaction, whereby ETErate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will transfer 30.8accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
ETP Senior Notes Offering
In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility and for general partnership purposes.
ETP August 2017 Units Offering
In August 2017, ETP issued 54 million ETP Common Units, ETE’s 45%common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

Rover Contribution Agreement
In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the Dakota Access Pipelineholding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.
ETP and Sunoco Logistics Merger
In April 2017, Energy Transfer Crude Oil Pipeline (collectively,Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction, with the “Bakken pipeline project”),Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and $879into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.
Sunoco LP Private Offering of Senior Notes
On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in cash (less amounts funded prior toaggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing by ETE for capital expenditures forof the Bakken pipeline project)asset purchase agreement with 7-Eleven to: 1) redeem in exchange for 30.8full its existing senior notes as of December 31, 2017, comprised of $800 million newly issued ETP Class H Units that, when combinedin aggregate principal amount of 6.250% senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; 2) repay in full and terminate the Sunoco LP Term Loan; 3) pay all closing costs and taxes in connection with the 50.2 million7-Eleven transaction; 4) redeem the outstanding Sunoco LP Series A Preferred Units as mentioned above; and 5) repurchase 17,286,859 common units owned by ETP as mentioned above.
Sunoco LP Convenience Store Sale
On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven (“SEI Fuel” and together with 7-Eleven, referred to herein collectively as “Buyers”). Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.3 billion.
Sunoco LP has signed definitive agreements with a commission agent to operate the approximately 207 retail sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the previously issued ETP Class H Units, generally entitle ETEannounced transaction with 7-Eleven, Inc. Conversion of these sites to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics. In addition, ETE and ETP agreed to reduce the IDR subsidies that ETE previously agreed to provide to ETP, with such reductions occurring in 2015 and 2016. This transactioncommission agent is expected to closeoccur in March 2015.the first quarter of 2018.
AcquisitionSunoco LP Real Estate Sale
On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, GulfOklahoma, and New Mexico markets which will be operated by Sunoco Logisticsa commission agent.
Permian Express Partners
In December 2014,February 2017, Sunoco Logistics acquiredformed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an additional 28.3%idle pipeline in southern Oklahoma, and its Patoka, Illinois

terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, ETP contributed an approximate 15% ownership interest in the West Texas Gulf Pipe Line Company from Chevron Pipe Line Company, increasing itsDakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to 88.6%.MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 11.4% was acquired from Southwest Pipeline Holding Company, LLC in January 2015.
Lone Star NGL Pipeline and Conversion Project
In November 2014, ETP and Regency announced that Lone Star will construct a 533 mile, 24- and 30-inch NGL pipeline from the Permian Basin to Mont Belvieu, Texas and convert Lone Star’s existing West Texas 12-inch NGL pipeline into crude oil/condensate service. The new pipeline and conversion projects, estimated to cost between $1.5 billion and $1.8 billion, are expected to be operational by the third quarter25% of 2016 and the first quartereach of 2017, respectively.
Gathering and Processing Construction Projects
In November 2014, ETP announced its plans to construct two new 200 million cubic feet per day cryogenic gas processing plants and associated gathering systems in the Eagle Ford and Eaglebine production areas.  ETP expects to have the first plant online by June 2015 and the second plant by the fourth quarter of 2015.
Lone Star Fractionator
In November 2014, ETP and Regency announced that Lone Star will construct a third natural gas liquids fractionator at its facility in Mont Belvieu, Texas, which will bring Lone Star’s total fractionation capacity at Mont Belvieu to 300,000 Bbls/d. Lone Star’s third fractionator is scheduled to be operational by December 2015.
Phillips 66 Joint Ventures
In October 2014, ETE, ETP and Phillips 66 formed two joint ventures to develop the previously announced Dakota Access Pipeline (“DAPL”) and Energy Transfer Crude Oil Pipeline (“ETCOP”) projects.ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETE hold an aggregate interest of 75% in each joint venture and ETP operates both pipeline systems. Phillips 66 owns the remaining 25% interests and funds its proportionate share of the construction costs. The DAPL and ETCOP projects are expectedETCO subsequent to begin commercial operations in the fourth quarter of 2016.this transaction.
ET Rover
In June 2014, ETP announced a natural gas pipeline project (now called “Rover”) to connect Marcellus and Utica shale supplies to markets in the Midwest, Great Lakes, and Gulf Coast regions of the United States and Canada. ETP has secured multiple, long-term binding shipper agreements on Rover. As a result of these binding agreements, the pipeline is substantially subscribed with 15- and 20-year fee-based contracts to transport up to 3.25 Bcf/d of capacity. Also, ETP recently announced that AE–Midco Rover, LLC (“AE–Midco”), has exercised its option to increase its equity ownership interest in Rover. As a result, AE–Midco (and an affiliate of AE–Midco) will own 35% of Rover and ETP will own 65%.

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MACS to Sunoco LP
In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units.
ETE Unit Repurchase
From January through May 2014, ETE repurchased approximately $1 billion of ETE common units under its buyback program.
Lake Charles LNG Transaction
In February 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE. This transaction was effective as of January 1, 2014.
In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 9 to our consolidated financial statements.
Results of OperationsInvestment in Lake Charles LNG
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletions, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, loss on extinguishment of debt, gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities includes unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations.
Based on the change in our reportable segments, we have adjusted the presentation of our segment results for the prior years to be consistent with the current year presentation.
Eliminations in the tables below include the following:
ETP’s Segment Adjusted EBITDA reflected 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA included its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star were included in eliminations.
ETP’s Segment Adjusted EBITDA reflected the results of SUGS from March 26, 2012 to April 30, 2013. Since the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also included the results of SUGS from March 26, 2012 to April 30, 2013.
ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG priorprovides terminal services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long term contracts with a wholly-owned subsidiary of BG Group plc (“BG”).
Lake Charles LNG is currently developing a natural gas liquefaction facility with BG for the export of LNG. In December 2015, Lake Charles LNG received authorization from the FERC to site, construct, and operate facilities for the liquefaction and export of natural gas. On February 15, 2016, Royal Dutch Shell plc completed its acquisition of BG. Shell announced in the second quarter of 2016 that they will delay making a final investment decision (“FID”) for the Lake Charles LNG Transaction, which was effective January 1, 2014. The project and Shell has not advised LCL of any change in the status of the project. In the event that each of LCL and Shell elect to make an affirmative FID, construction of the project would be expected to commence promptly thereafter and first LNG exports would commence about four years later.

Asset Overview
Investment in Lake Charles LNG segment reflected the resultsETP
The descriptions below include summaries of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segments for the year ended December 31, 2013significant assets within ETP’s operations. Amounts, such as capacities, volumes and the period from March 26, 2012 to December 31, 2012. Therefore, the results of Lake Charles LNG weremiles included in eliminations for 2013the descriptions below are approximate and 2012.are based on information currently available; such amounts are subject to change based on future events or additional information.

The following details the assets in ETP’s operations:
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Consolidated ResultsThe following details pipelines and storage facilities in ETP’s intrastate transportation and storage operations:
 Years Ended December 31,  
 2014 2013 Change
Segment Adjusted EBITDA:     
Investment in ETP$4,829
 $3,953
 $876
Investment in Regency1,172
 608
 564
Investment in Lake Charles LNG195
 187
 8
Corporate and Other(97) (43) (54)
Adjustments and eliminations(259) (338) 79
Total5,840
 4,367
 1,473
Depreciation, depletion and amortization(1,724) (1,313) (411)
Interest expense, net of interest capitalized(1,369) (1,221) (148)
Gain on sale of AmeriGas common units177
 87
 90
Goodwill impairments(370) (689) 319
Gains (losses) on interest rate derivatives(157) 53
 (210)
Non-cash unit-based compensation expense(82) (61) (21)
Unrealized gains on commodity risk management activities116
 48
 68
Inventory valuation adjustments(473) 3
 (476)
Losses on extinguishments of debt(25) (162) 137
Adjusted EBITDA related to discontinued operations(27) (76) 49
Adjusted EBITDA related to unconsolidated affiliates(748) (727) (21)
Equity in earnings of unconsolidated affiliates332
 236
 96
Non-operating environmental remediation—
 (168) 168
Other, net(73) (2) (71)
Income from continuing operations before income tax expense1,417
 375
 1,042
Income tax expense357
 93
 264
Income from continuing operations1,060
 282
 778
Income from discontinued operations64
 33
 31
Net income$1,124
 $315
 $809
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline Pipeline Throughput Capacity
(Bcf/d)		 Working Storage Capacity
(Bcf/d)
ET Fuel System 100% 2,780
 5.2
 11.2
Oasis Pipeline 100% 750
 2.3
 —
HPL System 100% 3,920
 5.3
 52.5
East Texas Pipeline 100% 460
 2.4
 —
RIGS Haynesville Partnership Co. 49.99% 450
 2.1
 —
Comanche Trail Pipeline 16% 195
 1.1
 —
Trans-Pecos Pipeline 16% 143
 1.4
 —
SeeThe following information describes ETP’s principal intrastate transportation and storage assets:
The ET Fuel System serves some of the detailed discussion of Segment Adjusted EBITDAmost prolific production areas in the Segment Operating Results section below.United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.
Depreciation, DepletionThe ET Fuel System also includes the Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and Amortization. Depreciation, depletionan injection capacity of 75 MMcf/d, and amortization increasedthe Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.
In addition, the ET Fuel System is integrated with ETP’s Godley processing plant which gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
The Oasis Pipeline is primarily as a result36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 Bcf/d of acquisitionsthroughput capacity moving west-to-east and growth projects,greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing its Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing ETP to bypass its processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas

in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing ETP to play an increase of $254 million at Regency primarilyimportant role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to depreciation, depletionits numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and amortization related to the PVR, Eagle Rock and Hoover acquisitions,Agua Dulce, as well as additional depreciation, depletionETP’s Bammel storage facility.
The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and amortization recorded from assets placed in service in 2014 and 2013.
Interest Expense, Neta peak injection rate of Interest Capitalized. Interest expense increased primarily due to0.6 Bcf/d. The Bammel storage facility is located near the following:
an increase of $140 million related to Regency primarily due to its issuance of $600 million of senior notes in April 2013, $400 million of senior notes in September 2013, $900 of million senior notes in February 2014 and $700 of million senior notes issued in July 2014, as well as the assumption of $1.2 billion of senior notes in the PVR AcquistionHouston Ship Channel market area and the exchange of $499 million of senior notes in the Eagle Rock Acquisition;Katy Hub, and
an increase of $11 million related is ideally suited to ETP primarily due to ETP’s issuance of $1.25 billion of senior notes in January 2013provide a physical backup for on-system and $1.5 billion of senior notes in September 2013; partially offset by
a reduction of $5 million for the Parent Company primarily related to a $1.1 billion principal paydown of the Parent Company’s $2 billion term loan in April 2013, net of interest related to incremental debt.
Gain on Sale of AmeriGas Common Units. During the year ended December 31, 2014 and 2013, ETP sold 18.9 million and 7.5 million, respectively, of the AmeriGas common units that were originally received in connection with the contribution of its propane

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business to AmeriGas in January 2012. ETP recorded a gain based on the sale proceeds in excess of the carrying amount of the units sold.off-system customers. As of December 31, 2014,2017, ETP had approximately 10.8 Bcf committed under fee-based arrangements with third parties and approximately 36.9 Bcf stored in the facility for ETP’s remainingown account.
The East Texas Pipeline connects three treating facilities, one of which ETP owns, with its Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect ETP’s Reed compressor station in Freestone County to its Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting ETP’s Cleburne to Carthage pipeline to the HPL System.
RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. The Partnership owns a 49.99% general partner interest in AmeriGas common units consistedRIGS.
Comanche Trail is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.
Trans-Pecos is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.
Interstate Transportation and Storage
The following information describes ETP’s principal interstate transportation and storage assets:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline 
Pipeline Throughput Capacity
(Bcf/d)
 
Working Gas Capacity
(Bcf/d)
Florida Gas Transmission Pipeline 50% 5,360
 3.1
 —
Transwestern Pipeline 100% 2,570
 2.1
 —
Panhandle Eastern Pipe Line 100% 5,980
 2.8
 83.9
Trunkline Gas Pipeline 100% 2,220
 0.9
 13.0
Tiger Pipeline 100% 195
 2.4
 —
Fayetteville Express Pipeline 50% 185
 2.0
 —
Sea Robin Pipeline 100% 830
 2.0
 —
Rover Pipeline 32.6% 713
 3.25
 —
Midcontinent Express Pipeline 50% 500
 1.8
 —
Gulf States 100% 10
 0.1
 —
The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of 3.1 million units heldBcf/d and approximately 5,360 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains over 81 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrials and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture between ETP and KMI.
The Transwestern Pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandles. Natural

gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
The Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan.
The Trunkline Gas Pipeline’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.
The Tiger Pipeline is an approximately 195-mile interstate natural gas pipeline with bi-directional capabilities, that connects to ETP’s dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.
The Fayetteville Express Pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express Pipeline is owned by a wholly-owned captive insurance company.50/50 joint venture with KMI.
Goodwill Impairments. In 2013, Lake Charles LNG recordedThe Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.
The Rover Pipeline is a $689 million goodwill impairment. new 713-mile natural gas pipeline designed to transport 3.25 Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market.
The declineMidcontinent Express Pipeline is an approximately 500-mile interstate pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline System in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI.
Gulf States owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
Midstream
The following details ETP’s assets in its midstream operations:
Description of Assets
Net Gas Processing Capacity
(MMcf/d)
 
Net Gas Treating Capacity
(MMcf/d)
South Texas Region:   
Southeast Texas System410
 510
Eagle Ford System1,920
 1,808
Ark-La-Tex Region1,025
 1,186
North Central Texas Region715
 212
Permian Region1,943
 1,580
Mid-Continent Region885
 20
Eastern Region—
 70
The following information describes ETP’s principal midstream assets:
South Texas Region:
The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plant (La Grange and Alamo) with aggregate capacity of 410 MMcf/d and natural gas treating facilities with aggregate capacity of 510 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process

the rich gas that flows through ETP’s gathering system to produce residue gas and NGLs. Residue gas is delivered into its intrastate pipelines and NGLs are delivered into ETP’s NGL pipelines to Lone Star.
ETP’s treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into ETP’s system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both ETP’s King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1,920 MMcf/d and multiple natural gas treating facilities with combined capacity of 1,808 MMcf/d. ETP’s Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to its intrastate transportation pipeline systems for deliveries of residue gas and are also connected with ETP’s NGL pipelines for delivery of NGLs to Lone Star.
Ark-La-Tex Region:
ETP’s Northern Louisiana assets are comprised of several gathering systems in the estimated fair value wasHaynesville Shale with access to multiple markets through interconnects with several pipelines, including ETP’s Tiger Pipeline. ETP’s Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1,186 MMcf/d.
ETP’s PennTex Midstream System is primarily due to changes related to (i) the structurelocated in Lincoln Parish, Louisiana, and capitalizationconsists of the planned LNG export project at Lake Charles LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including globalLincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas pricesprocessing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to ETP’s processing plants and relative spreads, as ofthird-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from ETP’s processing plants, including connections with pipelines that provide access to the date of our assessment (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export projectPerryville Hub and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility.  An assessment of these factorsother markets in the fourth quarterGulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from ETP’s processing plants.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline. Collectively, the eight natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada and Brookeland) have an aggregate capacity of 2013 led to a conclusion that1,025 MMcf/d.
Through the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount. 
During the fourth quarter of 2014, a $370 million goodwill impairment was recorded related to Regency’s Permian Basin gathering and processing operations. systems described above and their interconnections with RIGS in north Louisiana, ETP offers producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
The declineNorth Central Texas System is an integrated system located in estimated fair valuefour counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. ETP’s North Central Texas assets include its Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 715 MMcf/d and aggregate treating capacity of 212 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of ETP’s system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that reporting unit was primarily drivenETP gathers and processes, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes ten processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther and Rebel) with an aggregate processing capacity of 1,618 MMcf/d, treating capacity of 1,580 MMcf/d, and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.
ETP owns a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. ETP operates the plant and related facilities on behalf of Mi Vida JV.

ETP owns a 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.
Mid-Continent Region:
The Mid-Continent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. ETP’s Mid-Continent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Mid-Continent Systems include fourteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray and Gray) with an aggregate capacity of 885 MMcf/d and one natural gas treating facility with aggregate capacity of 20 MMcf/d.
ETP operates its Mid-Continent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
ETP also owns the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
Eastern Region:
The Eastern Region assets are located in nine counties in Pennsylvania, three counties in Ohio, three counties in West Virginia, and gather natural gas from the significant declineMarcellus and Utica basins. ETP’s Eastern Region assets include approximately 500 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems. The fresh water pipeline system and Ohio gathering assets are held by jointly-owned entities.
ETP also owns a 51% membership interest in commodity pricesAqua – PVR, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
ETP and Traverse ORS LLC, a subsidiary of Traverse Midstream Partners LLC, own a 75% and 25% membership interest, respectively, in the ORS joint venture. On behalf of ORS, ETP operates ORS’s Ohio Utica River System (the “ORS System”), which consists of 47 miles of 36-inch and 13 miles of 30-inch gathering trunklines that delivers up to 2.1 Bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and others.

NGL and Refined Products Transportation and Services
The following details the assets in ETP’s NGL and refined products transportation and services operations:
Description of Assets
Miles of Liquids Pipeline (2)
 
Pipeline Throughput Capacity
(MBbls/d)
 
NGL Fractionation / Processing Capacity
(MBbls/d)
 
Working Storage Capacity
(MBbls)
Liquids Pipelines:       
Lone Star Express535
 507
 —
 —
West Texas Gateway Pipeline512
 240
 —
 —
Lone Star1,617
 120
 —
 —
Mariner East300
 70
    
Mariner South67
 200
    
Mariner West395
 50
    
Other NGL Pipelines645
 591
 —
 —
Liquids Fractionation and Services Facilities:       
Mont Belvieu Facilities163
 42
 520
 50,000
Sea Robin Processing Plant1
—
 —
 26
 —
Refinery Services1
103
 —
 25
 —
Hattiesburg Storage Facilities—
 —
 —
 3,000
NGLs Terminals:       
Nederland—
 —
 —
 1,000
Marcus Hook Industrial Complex—
 —
 90
 5,000
Inkster—
 —
 —
 1,000
Refined Products Pipelines2,200
 800
 —
 —
Refined Products Terminals:       
Eagle Point—
 —
 —
 6,000
Marcus Hook Industrial Complex—
 —
 —
 1,000
Marcus Hook Tank Farm—
 —
 —
 2,000
Marketing Terminals—
 —
 —
 8,000
(1)
Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of 850 MMcf/d and 54 MMcf/d, respectively.
(2)
Miles of pipeline as reported to PHMSA.
The following information describes ETP’s principal NGL and refined products transportation and services assets:
The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.
The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including ETP’s Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the resulting impactfirst quarter of 2016, respectively. The second phase of the project, referred to future commodity prices as well as increasesMariner East 2, will expand the total takeaway capacity to 345 MBbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in future estimatedthe second quarter of 2018.

The Mariner South pipeline is part of a joint project with Lone Star to deliver export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to ETP’s marine terminal in Nederland, Texas.
The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations and maintenance expenses. An assessment of these factors in the fourth quarter of 2014 led2013, with capacity to transport approximately 50 MBbls/d.
Refined products pipelines include approximately 2,200 miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. These operations include ETP’s controlling financial interest in Inland Corporation (“Inland”). The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375 MBbls/d, the 45-mile Freedom pipeline with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140 MBbls/d.
ETP’s Mont Belvieu storage facility is an integrated liquids storage facility with over 50 million Bbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
ETP’s Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator V is currently under construction and is scheduled to be operational by the third quarter of 2018.
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.
Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana.  The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components.  The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 103 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 million Bbls of salt dome capacity, providing 100% fee-based cash flows.
The Nederland terminal, in addition to crude oil activities, also provides approximately 1 million Bbls of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be exported via ship.
The Marcus Hook Industrial Complex includes fractionation, terminalling and storage assets, with a capacity of approximately 2 million Bbls of NGL storage capacity in underground caverns, 3 million Bbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 million Bbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for the Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million Bbls of NGLs. ETP uses the Inkster terminal's storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
ETP has approximately 40 refined products terminals with an aggregate storage capacity of approximately 8 million Bbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million Bbls, and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million Bbls of refined products storage. The tank farm historically served Sunoco Inc.’s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.’s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on ETP’s refined products pipelines.
The Eastern refined products pipelines consists of approximately 470 miles of 6-inch to 24-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, approximately 162 miles of 8-inch refined products pipeline in western New York and approximately 182 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
The Mid-Continent refined products pipelines primarily consists of approximately 212 miles of 3-inch to 12-inch refined products pipelines in Ohio, approximately 85 miles of 6-inch to 12-inch refined products pipeline in Western Pennsylvania and approximately 52 miles of 8-inch refined products pipeline in Michigan.
The Southwest refined products pipelines is located in Eastern Texas and consists primarily of approximately 300 miles of 8-inch diameter refined products pipeline.
The Inland refined products pipeline, approximately 350 miles of pipeline in Ohio, consists of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 205 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 53 miles of 8-inch diameter refined products pipeline in western Ohio and the remaining refined products pipeline primarily consists of 5-inch diameter pipeline in Northeast Ohio.
Crude Oil Transportation and Services
The following details ETP’s pipelines and terminals in its crude oil transportation and services operations:
Description of Assets
Miles of Crude Pipeline (1)
Working Storage Capacity
(MBbls)
Dakota Access Pipeline1,172
—
Energy Transfer Crude Oil Pipeline743
—
Bayou Bridge Pipeline49
—
Permian Express Pipelines1,712
—
Other Crude Oil Pipelines5,682
—
Nederland Terminal—
26,000
Fort Mifflin Terminal—
570
Eagle Point Terminal—
1,000
Midland Terminal—
2,000
Marcus Hook Industrial Complex—
1,000
Patoka, Illinois Terminal—
2,000
(1)
Miles of pipeline as reported to PHMSA.
ETP’s crude oil operations consist of an integrated set of pipeline, terminalling, and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details ETP’s assets in its crude oil transportation and services operations:
Crude Oil Pipelines
ETP’s crude oil pipelines consist of approximately 9,358 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States, including ETP’s wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC (“PET”), and Mid-Valley Pipeline Company (“Mid-Valley”). Additionally, ETP has equity ownership interests in two crude oil pipelines.

ETP’s crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. ETP’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a conclusionnumber of refineries.
Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915 mile pipeline with an initial capacity of 470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including ETP’s crude terminal in Nederland Texas.
The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
Dakota Access went into service on June 1, 2017 and consists of approximately 1,172 miles of 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the ETCO Pipeline for delivery to the Gulf Coast, or can be transported via other pipelines to refining markets throughout the Midwest.
ETCO went into service on June 1, 2017 and consists of more than 743 miles consisting of 678 miles of mostly 30-inch converted natural gas pipeline and 65 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETP and Phillips 66, in which ETP has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.
When completed the Bayou Bridge Pipeline will have a capacity expandable to approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, which origins in multiple locations in Western Texas.
Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies its Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
Crude Oil Terminals
Nederland. The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 26 million Bbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland terminal can receive crude oil at four of its five ship docks and four barge berths. The four ship docks are capable of receiving over 2 million Bbls/d of crude oil. In addition to ETP’s crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United

States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million Bbls.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has two ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/d of crude oil to ETP’s crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin terminal complex by charging fees based on throughput.
The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.
The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of approximately 3 million Bbls. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via ETP’s pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via ETP’s pipelines.
Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1 million Bbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls of crude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.
Marcus Hook Industrial Complex. The Marcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 million Bbls.
Patoka, Illinois Terminal. The Patoka, Illinois terminal is a tank farm and was contributed by ExxonMobil to the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 2 million Bbls of crude oil storage.
Crude Oil Acquisition and Marketing
ETP’s crude oil acquisition and marketing operations are conducted using ETP’s assets, which include approximately 370 crude oil transport trucks and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets.
All Other
Equity Method Investments
Sunoco LP. ETP has an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, ETP’s investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, ETP’s investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

PES. ETP has a non-controlling interest in PES, comprising 33% of PES’ outstanding common units. As discussed in “ETP’s Other Operations and Investments” above, PES Holdings and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018.
Contract Services Operations
ETP owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. ETP’s contract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
ETP owns all of the outstanding equity interests of CDM, which operates a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas. As discussed in “Strategic Transactions,” in January 2018, ETP entered into an agreement to contribute CDM to USAC.
ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of ETT. ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’s other operations.
Natural Resources Operations
ETP’s Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. ETP also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2017, ETP owned or controlled approximately 766 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.
Liquefaction Project
LCL, an entity whose parent is owned 60% by ETE and 40% by ETP, is in the process of developing a liquefaction project at the site of ETE’s existing regasification facility in Lake Charles, Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc (now "Shell") related to this project expired in February 2017. On June 28, 2017, LCL signed a memorandum of understanding with Korea Gas Corporation and Shell to study the feasibility of a joint development of the Lake Charles liquefaction project. The project would utilize existing dock and storage facilities owned by ETE located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia).  Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the estimated fair valueparties will determine to proceed to develop this project.
The liquefaction project is expected to consist of Regency’s Permian reporting unit was lessthree LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of exporting and importing LNG. Shell is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project would be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL. In March 2013, LCL obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”). The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively.

ETP has received its wetlands permits from the United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.
Investment in Sunoco LP
The following details the assets of Sunoco LP:
Wholesale Subsidiaries
Sunoco LLC, a Delaware limited liability company, primarily distributes motor fuel across 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama and the Greater Dallas, Texas metroplex.
Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands.
Retail Subsidiaries
Susser Petroleum Property Company LLC, a Delaware limited liability company, primarily owns and leases convenience store properties.
Susser, a Delaware corporation, sells motor fuel and merchandise in Texas, New Mexico, and Oklahoma through Stripes-branded convenience stores.
Sunoco Retail, a Pennsylvania limited liability company, owns and operates convenience stores that sell motor fuel and merchandise primarily in Pennsylvania, New York, and Florida.
MACS Retail LLC, a Virginia limited liability company, owns and operates convenience stores in Virginia, Maryland, and Tennessee.
Aloha Petroleum, Ltd., a Hawaii corporation, owns and operates convenience stores on the Hawaiian Islands.
As of December 31, 2017, prior to the closing of the amended and restated purchasing agreement with 7-Eleven, Sunoco LP’s retail segment operated approximately 1,348 convenience stores and retail fuel outlets. Sunoco LP’s retail convenience stores operates under several brands, including its proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. Sunoco LP has company operated sites in more than its carrying amount.20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.
Gains (Losses)As of December 31, 2017, Sunoco LP operated approximately 746 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on Interest Rate Derivatives.local customer demand and preferences. Sunoco LP built approximately 265 large-format convenience stores from January 2000 through December 31, 2017. Sunoco LP has implemented its proprietary, in-house Laredo Taco Company restaurant concept in approximately 477 Stripes convenience stores. Sunoco LP also owns and operates ATM and proprietary money order systems in most Stripes stores and provides other services such as lottery, prepaid telephone cards, wireless services and car washes.
As of December 31, 2017, Sunoco LP operated approximately 441 retail convenience stores and fuel outlets, primarily under its proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 404 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.
As of December 31, 2017, Sunoco LP operated approximately 161 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2017, MACS operated approximately 107 retail convenience stores and Aloha operated approximately 54 Aloha, Shell, and Mahalo branded fuel stations.
Investment in Lake Charles LNG
Regasification Facility
Lake Charles LNG, a wholly-owned subsidiary of ETE, owns a LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/day.

Liquefaction Project
LCL, an entity owned 60% by ETE and 40% by ETP, is in the process of developing the liquefaction project in conjunction with BG pursuant to a project development agreement entered into in September 2013 and scheduled to expire at the end of February 2017, subject to the parties’ right to mutually extend the term. Pursuant to this agreement, each of LCL and BG are obligated to pay 50% of the development expenses for the liquefaction project, subject to reimbursement by the other party if such party withdraws from the project prior to both parties making an affirmative FID to become irrevocably obligated to fully develop the project, subject to certain exceptions. The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility will become a bi-directional facility capable of exporting and importing LNG. BG is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project is expected to be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.
The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of exporting and importing LNG. Shell is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project would be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL. In March 2013, LCL obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”).  In July 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”).  The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively. 
In addition, We have received our wetlands permits from the United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.
Competition
Natural Gas
The business of providing natural gas gathering, compression, treating, transporting, storing and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage operations are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.
We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our interest rate derivativescompetitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.
In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

NGL
In markets served by our NGL pipelines, we face competition with other pipeline companies, including those affiliated with major oil, petrochemical and natural gas companies, and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service. We face competition with other storage facilities based on fees charged and the ability to receive and distribute the customer’s products. We compete with a number of NGL fractionators in Texas and Louisiana. Competition for such services is primarily based on the fractionation fee charged.
Crude Oil and Products
In markets served by our products and crude oil pipelines, we face competition from other pipelines as well as rail and truck transportation. Generally, pipelines are the lowest cost method for long-haul, overland movement of products and crude oil. Therefore, the most significant competitors for large volume shipments in the areas served by our pipelines are other pipelines. In addition, pipeline operations face competition from rail and trucks that deliver products in a number of areas that our pipeline operations serve. While their costs may not designatedbe competitive for longer hauls or large volume shipments, rail and trucks compete effectively for incremental and marginal volume in many areas served by our pipelines.
With respect to competition from other pipelines, the primary competitive factors consist of transportation charges, access to crude oil supply and market demand. Competitive factors in crude oil purchasing and marketing include price and contract flexibility, quantity and quality of services, and accessibility to end markets.
Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.
Wholesale Fuel Distribution and Retail Marketing
In our wholesale fuel distribution business, we compete primarily with other independent motor fuel distributors. The markets for distribution of wholesale motor fuel and the large and growing convenience store industry are highly competitive and fragmented, which results in narrow margins. We have numerous competitors, some of which may have significantly greater resources and name recognition than we do. Significant competitive factors include the availability of major brands, customer service, price, range of services offered and quality of service, among others. We rely on our ability to provide value-added and reliable service and to control our operating costs in order to maintain our margins and competitive position.
In our retail business, we face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, supermarkets, drugstores, dollar stores, club stores and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending on the geographical area. It also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition. We compete by pricing gasoline competitively, combining our retail gasoline business with convenience stores that provide a wide variety of products, and using advertising and promotional campaigns.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as hedgesnecessary. The Partnership also uses industry standard commercial agreements which allow for accounting purposes; therefore, the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies, and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory

changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in fair valueour financial position or results of operations as a consequence of counterparty non-performance.
Natural gas transportation and midstream revenues are recordedderived significantly from companies that engage in earnings each period. Lossesexploration and production activities. The discovery and development of new shale formations across the United States has created an abundance of natural gas and crude oil resulting in a negative impact on interest rate derivatives duringprices in recent years for natural gas and crude oil. As a result, some of our exploration and production customers have been adversely impacted; however, we are monitoring these customers and mitigating credit risk as necessary.
During the year ended December 31, 2014 resulted2017, none of our customers individually accounted for more than 10% of our consolidated revenues.
Regulation of Interstate Natural Gas Pipelines.The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act (“NGA”), the FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. The Florida Gas Transmission, Transwestern, Panhandle Eastern, Trunkline Gas, Tiger, Fayetteville Express, Sea Robin, Gulf States and Midcontinent Express pipelines transport natural gas in interstate commerce and thus each qualifies as a “natural-gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We also hold certain natural gas storage facilities that are subject to the FERC’s regulatory oversight under the NGA.
The FERC’s NGA authority includes the power to:
approve the siting, construction and operation of new facilities;
review and approve transportation rates;
determine the types of services our regulated assets are permitted to perform;
regulate the terms and conditions associated with these services;
permit the extension or abandonment of services and facilities;
require the maintenance of accounts and records; and
authorize the acquisition and disposition of facilities.
Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from decreasesunduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are required to be on file with the FERC. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition warrants such discounts. Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer a cost-based recourse rate available to a prospective shipper as an alternative to the negotiated rate. Natural gas companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. Existing tariff rates may be challenged by complaint or on FERC’s own motion, and if found unjust and unreasonable, may be altered on a prospective basis from no earlier than the date of the complaint or initiation of a proceeding by the FERC. The FERC must also approve all rate changes. We cannot guarantee that the FERC will allow us to charge rates that fully recover our costs or continue to pursue its approach of pro-competitive policies.

For two of our NGA-jurisdictional natural gas companies, Tiger and Fayetteville Express, the large majority of capacity in those pipelines is subscribed for lengthy terms under FERC-approved negotiated rates.  However, as indicated above, cost-based recourse rates are also offered under their respective tariffs.
Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of electric energy or natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction: (i) to defraud using any device, scheme or artifice; (ii) to make any untrue statement of material fact or omit a material fact; or (iii) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). With regard to our physical purchases and sales of natural gas, NGLs or other energy commodities; our gathering or transportation of these energy commodities; and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability

to assess or seek civil penalties of up to approximately $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Failure to comply with the NGA, the Energy Policy Act of 2005, the CEA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.
Regulation of Intrastate Natural Gas and NGL Pipelines.  Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates and terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates and terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline, ET Fuel System, Trans-Pecos and Comanche Trail are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the TRRC. Our intrastate pipeline and storage operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.
Our NGL pipelines and operations may also be or become subject to state public utility or related jurisdiction which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities. In addition, the rates, terms and conditions for shipments of NGLs on our pipelines are subject to regulation by FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all NGLs shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of Sales of Natural Gas and NGLs.The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation.
To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to the use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.
Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those operations of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom we compete.
Regulation of Gathering Pipelines.  Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines in Texas, Louisiana and West Virginia that we believe meet the traditional tests the FERC uses to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject

of substantial litigation and varying interpretations, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by the FERC, the courts and Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.
Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.
We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Regulation of Interstate Crude Oil, NGL and Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the ICA, the EPAct of 1992, and related rules and orders. The ICA requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariff rates charged by us ultimately will be upheld if challenged, management believes that the tariff rates now in effect for our pipelines are within the maximum rates allowed under current FERC policies and precedents.
For many locations served by our product and crude pipelines, we are able to establish negotiated rates.  Otherwise, we are permitted to charge cost-based rates, or in many cases, grandfathered rates based on historical charges or settlements with our customers. To the extent we rely on cost-of-service ratemaking to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise. In 2005, FERC issued a policy statement stating that it would permit common carriers, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. Whether a pipeline’s owners have such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for common carriers that are organized as pass-through entities, it still entails rate risk due to the FERC’s case-by-case review approach. The application of this policy, as well as any decision by

FERC regarding our cost of service, may also be subject to review in the courts. In December 2016, FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs. FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect to the notice of inquiry ended on April 7, 2017. The outcome of the inquiry is still pending.
Finally, in November 2017 FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline.  In particular, FERC’s November 2017 order prohibits  buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service  is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss.  Several parties have requested that FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order.  We are unable to predict how FERC will respond to such requests.  Depending on how FERC responds, it could have an impact on the rates we are permitted to charge.
EPAct 1992 required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPIFG. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2011 and ending June 30, 2016, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPIFG plus 2.65%. Beginning July 1, 2016, the indexing method provided for annual changes equal to the change in PPIFG plus 1.23%. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior 2 years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward interestthe full indexed increase to a future period. The comment period with respect to the proposed rules ended on March 17, 2017. FERC has taken no further action on the proposed rule to date.
Finally, in November 2017 FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline.  In particular, FERC’s November 2017 order prohibits  buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service  is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss.  Several parties have requested that FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order.  We are unable to predict how FERC will respond to such requests.  Depending on how FERC responds, it could have an impact on the rates we are permitted to charge.
Regulation of Intrastate Crude Oil, NGL and Products Pipelines. Some of our crude oil, NGL and products pipelines are subject to regulation by the TRRC, the PA PUC, and the Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.
In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of Pipeline Safety.Our pipeline operations are subject to regulation by the DOT, through the PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA,

as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Failure to comply with the pipeline safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays in permitting or the performance of projects, or the issuance of injunctions limiting or prohibiting some or all of our operations in the affected area.
The HLPSA and NGPSA have been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”). The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum penalty caps do not apply to certain civil enforcement actions. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $209,002 per day, with a maximum of $2,090,022 for a series of violations. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.
In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which we conduct operations typically have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines. Under such state regulatory programs, states have the authority to conduct pipeline inspections, to investigate accidents and to oversee compliance and enforcement, safety programs and record maintenance and reporting. Congress, PHMSA and individual states may pass or implement additional safety requirements that could result in increased compliance costs for us and other companies in our industry. For example, federal construction, maintenance and inspection standards under the NGPSA that apply to pipelines in relatively populated areas may not apply to gathering lines running through rural regions. This “rural gathering exemption” under the NGPSA presently exempts substantial portions of our gathering facilities located outside of cities, towns or any area designated as residential or commercial from jurisdiction under the NGPSA, but does not apply to our intrastate natural gas pipelines. In recent years, the PHMSA has considered changes to this rural gathering exemption, including publishing an advance notice of proposed rulemaking relating to gas pipelines in 2011, in which the agency sought public comment on possible changes to the definition of “high consequence areas” and “gathering lines” and the strengthening of pipeline integrity management requirements. In April 2016, pursuant to one of the requirements of the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that, among other things, would expand certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; require natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and require certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has not yet finalized the March 2016 proposed rulemaking.
In January 2017, PHMSA issued a final rule amending federal safety standards for hazardous liquid pipelines. The final rule is the latest step in a lengthy rulemaking process that began in 2010 with a request for comments and continued with publication of a rulemaking proposal in October 2015. The general effective date of this final rule is six months from publication in the Federal Register, but it is currently subject to further administrative review in connection with the transition of Presidential administrations and thus, implementation of this final rule remains uncertain. The final rule addresses several areas including reporting requirements for gravity and unregulated gathering lines, inspections after weather or climatic events, leak detection system requirements, revisions to repair criteria and other integrity management revisions. In addition, PHMSA issued regulations on January 23, 2017, on operator qualification, cost recovery, accident and incident notification and other pipeline safety changes that are now effective. These regulations are also subject, however, to potential further review in connection with the transition of Presidential

administrations. Historically, our pipeline safety costs have not had a material adverse effect on our business or results of operations but there is no assurance that such costs will not be material in the future, whether due to elimination of the rural gathering exemption or otherwise due to changes in pipeline safety laws and regulations.
In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the federal OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators, including the Texas Railroad Commission, have in recent years, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. To the extent that these actions are pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.
Environmental Matters
General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering, processing, storage and transmission of natural gas and the storage and transportation of NGLs, crude oil and refined products is subject to stringent federal, tribal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and criminal sanctions, third-party claims for personal injury or property damage, capital expenditures to retrofit or upgrade our facilities and programs, or curtailment or cancellation of permits on operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of planning, permitting, constructing and operating our plants, pipelines and other facilities. As a result of these laws and regulations, our construction and operation costs include capital, operating and maintenance cost items necessary to maintain or upgrade our equipment and facilities.
We have implemented procedures designed to ensure that governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. Historically, our environmental compliance costs have not had a material adverse effect on our business, results of operations or financial condition; however, there can be no assurance that such costs will not be material in the future. For example, we cannot be certain, however, that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent environmental laws and regulations or unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.
Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to strict, joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our forward-starting swapsordinary operations we generate wastes that may fall within that definition or that may be subject to other waste disposal laws and regulations. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed.
We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, as amended, (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial

portion of the RCRA hazardous waste requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent non-hazardous management standards. From time to time, the EPA has considered or third parties have petitioned the agency on the adoption of stricter handling, storage and disposal standards for nonhazardous wastes, including certain wastes associated with the exploration, development and production of crude oil and natural gas. For example, following the filing of a lawsuit by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the United States District Court for the District of Columbia on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense and, in the case of our oil and natural gas exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in value. Conversely, increases in forward interest rates resulted in gainsdemand for our processing, transportation and storage services.
We currently own or lease sites that have been used over the years by prior owners and lessees and by us for various activities related to gathering, processing, storage and transmission of natural gas, NGLs, crude oil and products. Waste disposal practices within the oil and gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on interest rate derivativesor under various sites during the year endedoperating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.
As of December 31, 2013.
Unrealized Gains on Commodity Risk Management Activities. See discussion2017 and 2016, accruals of $372 million and $344 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover estimated material environmental liabilities including, for example, certain matters assumed in connection with our acquisition of the unrealized gains on commodity riskHPL System, our acquisition of Transwestern, potential environmental liabilities for three sites that were formerly owned by Titan Energy Partners, L.P. or its predecessors, and the predecessor owner’s share of certain environmental liabilities of ETC OLP.
The Partnership is subject to extensive and frequently changing federal, tribal, state and local laws and regulations, including those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and composition of fuels. These laws and regulations require environmental assessment and remediation efforts at many of Sunoco, Inc.’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $284 million and $289 million at December 31, 2017 and 2016, respectively, which is included in the discussiontotal accruals above. These legacy sites that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that are no longer operated by Sunoco, Inc., closed and/or sold refineries and other formerly owned sites. In December 2013, a wholly-owned captive insurance company was established for these legacy sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. As of segment results below.December 31, 2017 the captive insurance company held $207 million of cash and investments.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recordedThe Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the inventory associated with Sunoco Logistics’ crude oileconomic environment. Engineering studies, historical experience and products inventoriesother factors are used to identify and ETP’s retail marketing operationsevaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Under various environmental laws, including the RCRA, the Partnership has initiated corrective remedial action at certain of its facilities, formerly owned facilities and at certain third-party sites. At the Partnership’s major manufacturing facilities, we have typically assumed continued industrial use and a containment/remediation strategy focused on eliminating unacceptable risks to human health or the environment. The remediation accruals for these sites reflect that strategy. Accruals include amounts designed to prevent or mitigate off-site migration and to contain the impact on the facility property, as well as to address known, discrete

areas requiring remediation within the plants. Remedial activities include, for example, closure of RCRA waste management units, recovery of hydrocarbons, handling of impacted soil, mitigation of surface water impacts and prevention or mitigation of off-site migration. A change in this approach as a result of commodity pricechanging the intended use of a property or a sale to a third party could result in a comparatively higher cost remediation strategy in the future.
In general, a remediation site or issue is typically evaluated on an individual basis based upon information available for the site or issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (for example, service station sites) in determining the amount of probable loss accrual to be recorded. The estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance allows us the minimum amount of the range to accrue. Accordingly, the low end of the range often represents the amount of loss which has been recorded.
In addition to the probable and estimable losses which have been recorded, management believes it is reasonably possible (that is, it is less than probable but greater than remote) that additional environmental remediation losses will be incurred. At December 31, 2017, the aggregate of such additional estimated maximum reasonably possible losses, which relate to numerous individual sites, totaled approximately $5 million, which amount is in excess of the $372 million in environmental accruals recorded on December 31, 2017. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics and retail assets, and in many cases, reflects the upper end of the loss ranges which are described above. Such estimates include potentially higher contractor costs for expected remediation activities, the potential need to use more costly or comprehensive remediation methods and longer operating and monitoring periods, among other things.
In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years, but management can provide no assurance that it would be over many years. If changes between periods.in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time.  As a result, from time to time, significant charges against income for environmental remediation may occur. And while management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position, it can provide no assurance.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $5 million, which is included in the total environmental accruals mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. Such future costs are not expected to have a material impact on our financial position, results of operations or cash flows, but management can provide no assurance.
Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We will incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. Historically, our costs for compliance with existing Clean Air Act and comparable state law requirements have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. The EPA and state agencies are often considering, proposing or finalizing new regulations that could impact our existing operations and the costs and timing of new infrastructure development. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering

the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.
Losses on ExtinguishmentsClean Water Act. The Federal Water Pollution Control Act of Debt. For1972, as amended, (“Clean Water Act”) and comparable state laws impose restrictions and strict controls regarding the year ended December 31, 2013, losses on extinguishmentdischarge of debt were primarily relatedpollutants, including hydrocarbon-bearing wastes, into state waters and waters of the United States. Pursuant to ETE’s refinancing transactions completed in December 2013.the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In May 2015, the EPA issued a final rule that attempts to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the United States Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In June 2015, the EPA and the United States Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the United States Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested May 2015 rule would not take effect until two years ended Decemberafter the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the United States Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. On January 31, 20142018, the EPA and 2013 also reflected lossesCorps finalized a rule that would delay applicability of $25 millionthe rule to two years from the rule’s publication in the Federal Register. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, our operations as well as our exploration and $7 million, respectively, relatedproduction customers’ drilling programs could incur increased costs and delays with respect to Regency’s repurchase of its senior notes during the respective periods.obtaining permits for dredge and fill activities in wetland areas.
Adjusted EBITDA RelatedSpills. Our operations can result in the discharge of regulated substances, including NGLs, crude oil or other products. The Clean Water Act, as amended by the federal Oil Pollution Act of 1990, as amended, (“OPA”), and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. The Clean Water Act and comparable state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges. The OPA subjects owners of covered facilities to Discontinued Operations. In 2014, amounts were related to a marketing business that was sold effective April 1, 2014. In 2013, amounts primarily related to Southern Union’s local distribution operations.
Adjusted EBITDA Related to Unconsolidated Affiliatesstrict joint and Equity in Earnings of Unconsolidated Affiliates. Amounts reflected primarily include our proportionate share of such amounts related to our equity method investees. See additional discussion of results in “Segment Operating Results” below.
Non-Operating Environmental Remediation. Non-operating environmental remediation was primarily due to Sunoco, Inc.’s recognition of environmental obligations related to closed sites.
Other, net. Includes amortization of regulatory assets, certain acquisition relatedpotentially unlimited liability for removal costs and other incomeconsequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and expense amounts.countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release of oil. The PHMSA, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans that are to be used in the event of a spill incident.
In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.
Endangered Species Act. The Endangered Species Act, as amended, restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may operate in areas that are currently designated as a habitat for endangered or threatened species or where the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened may occur in which event such one or more developments could cause us to incur additional costs, to develop habitat conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas. Moreover, such designation of previously unprotected species as threatened or endangered in areas where our oil and natural gas exploration and production customers operate could cause our

customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.
Climate Change. Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.
Income Tax ExpenseFederal agencies also have begun directly regulating emissions of methane, a GHG, from Continuing Operations.oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, the Subpart OOOOa standards have been subject to attempts by the EPA to stay portions of those standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. This rule, should it remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the United States State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.
Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is

difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
Employee Health and Safety. Income tax expenseWe are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Historically, our costs for OSHA required activities, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances, have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
Employees
As of December 31, 2017, ETE and its consolidated subsidiaries employed an aggregate of 29,486 employees, 1,544 of which are represented by labor unions. We and our subsidiaries believe that our relations with our employees are satisfactory.
SEC Reporting
We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.
ITEM 1A.  RISK FACTORS
In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. ETP, Panhandle and Sunoco LP file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information. The risk factors set forth below, and those included in ETP’s, Panhandle’s and Sunoco LP’s Annual Reports, are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.
Risks Inherent in an Investment in Us
Cash distributions are not guaranteed and may fluctuate with our performance or other external factors.
The Parent company’s principal source of earnings and cash flow is cash distributions from ETP and Sunoco LP. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the earningslevel of distributions ETP and Sunoco LP make to their partners. ETP and Sunoco LP may not be able to continue to make quarterly distributions at their current level or increase their quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP or Sunoco LP increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP or Sunoco LP to us.
Our ability to distribute cash received from ETP and Sunoco LP to our Unitholders is limited by a number of factors, including:
interest expense and principal payments on our indebtedness;
restrictions on distributions contained in any current or future debt agreements;
our general and administrative expenses;
expenses of our taxable subsidiaries. subsidiaries other than ETP and Sunoco LP, including tax liabilities of our corporate subsidiaries, if any; and
reserves our General Partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors, many of which are beyond our control or the control of our General Partner.
Our cash flow depends primarily on the cash distributions we receive from our partnership interests, including the incentive distribution rights, in ETP and Sunoco LP and, therefore, our cash flow is dependent upon the ability of ETP and Sunoco LP to make distributions in respect of those partnership interests.
We do not have any significant assets other than our partnership interests in ETP and Sunoco LP and our LNG business. As a result, our cash flow depends on the performance of ETP and Sunoco LP and their respective subsidiaries and ETP’s and Sunoco LP’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP and Sunoco LP.
The amount of cash that ETP and Sunoco LP can distribute to their partners, including us, each quarter depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter and will depend upon, among other things:
the amount of natural gas, NGLs, crude oil and refined products transported through ETP’s pipelines and gathering systems;
the level of throughput in processing and treating operations;
the fees charged and the margins realized by ETP and Sunoco LP for their services;
the price of natural gas, NGLs, crude oil and refined products;
the relationship between natural gas, NGL and crude oil prices;
the amount of cash distributions ETP receives with respect to the Sunoco LP common units that ETP or its subsidiaries own;
the weather in their respective operating areas;
the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;
the level of their respective operating costs and maintenance and integrity capital expenditures;
the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;
prevailing economic conditions; and
the level and results of their respective derivative activities.
In addition, the year endedactual amount of cash that ETP and Sunoco LP will have available for distribution will also depend on other factors, such as:
the level of capital expenditures they make;
the level of costs related to litigation and regulatory compliance matters;
the cost of acquisitions, if any;
the levels of any margin calls that result from changes in commodity prices;
debt service requirements;
fluctuations in working capital needs;
their ability to borrow under their respective revolving credit facilities;
their ability to access capital markets;
restrictions on distributions contained in their respective debt agreements; and
the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.
ETE does not have any control over many of these factors, including the level of cash reserves established by the board of directors and ETP’s General Partners. Accordingly, we cannot guarantee that ETP and Sunoco LP will have sufficient available cash to pay a specific level of cash distributions to its partners.

Furthermore, Unitholders should be aware that the amount of cash that ETP and Sunoco LP have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, ETP and Sunoco LP may declare and/or pay cash distributions during periods when they record net losses. Please read “Risks Related to the Businesses of our Subsidiaries” included in this Item 1A for a discussion of further risks affecting ETP’s and Sunoco LP’s ability to generate distributable cash flow.
We may issue an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.
Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:
our Unitholders’ current proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each Common Unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding Common Unit may be diminished; and
the market price of our Common Units may decline.
In addition, ETP and Sunoco LP may sell an unlimited number of limited partner interests without the consent of the respective Unitholders, which will dilute existing interests of the respective Unitholders, including us. The issuance of additional Common Units or other equity securities by ETP or Sunoco LP will have essentially the same effects as detailed above.
ETP and Sunoco LP may issue additional Common Units, which may increase the risk that each Partnership will not have sufficient available cash to maintain or increase its per unit distribution level.
The partnership agreements of ETP and Sunoco LP allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by each respective partnership will have the following effects:
Unitholders’ current proportionate ownership interest in each partnership will decrease;
the amount of cash available for distribution on each common unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of each partnership’s common units may decline.
The payment of distributions on any additional units issued by ETP and Sunoco LP may increase the risk that either partnership may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.
Unitholders have limited voting rights and are not entitled to elect the General Partner or its directors. In addition, even if Unitholders are dissatisfied, they cannot easily remove the General Partner.
Unlike the holders of common stock in a corporation, Unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner and will have no right to elect our General Partner or the officers or directors of our General Partner on an annual or other continuing basis.
Furthermore, if our Unitholders are dissatisfied with the performance of our General Partner, they may be unable to remove our General Partner. Our General Partner may not be removed except, among other things, upon the vote of the holders of at least 66 2/3% of our outstanding units. As of December 31, 2014 included2017, our directors and executive officers directly or indirectly own approximately 27% of our outstanding Common Units. It will be particularly difficult for our General Partner to be removed without the impactconsent of our directors and executive officers. As a result, the price at which our Common Units will trade may be lower because of the Lake Charles LNG Transaction,absence or reduction of a takeover premium in the trading price.

Furthermore, Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the General Partner and its affiliates, cannot be voted on any matter.
Our General Partner may, in its sole discretion, approve the issuance of partnership securities and specify the terms of such partnership securities.
Pursuant to our partnership agreement, our General Partner has the ability, in its sole discretion and without the approval of the Unitholders, to approve the issuance of securities by the Partnership at any time and to specify the terms and conditions of such securities. The securities authorized to be issued may be issued in one or more classes or series, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership securities), as shall be determined by our General Partner, including:
the right to share in the Partnership’s profits and losses;
the right to share in the Partnership’s distributions;
the rights upon dissolution and liquidation of the Partnership;
whether, and the terms upon which, was treatedthe Partnership may redeem the securities;
whether the securities will be issued, evidenced by certificates and assigned or transferred; and
the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.
Please see “—We may issue an unlimited number of limited partner interests without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.” above.
The control of our General Partner may be transferred to a third party without Unitholder consent.
The General Partner may transfer its general partner interest to a third party without the consent of the Unitholders. Furthermore, the members of our General Partner may transfer all or part of their ownership interest in our General Partner to a third party without the consent of the Unitholders. Any new owner or owners of our General Partner or the general partner of the General Partner would be in a position to replace the directors and officers of our General Partner with its own choices and to control the decisions made and actions taken by the board of directors and officers.
We are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative and legal services necessary to operate our business.
We rely on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETP’s midstream business. Mr. Warren has been integral to the success of ETP’s midstream and intrastate transportation and storage businesses because of his ability to identify and develop strategic business opportunities. Losing the leadership of Mr. Warren could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.
ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.
Cost reimbursements due to our General Partner may be substantial and may reduce our ability to pay the distributions to our Unitholders.
Prior to making any distributions to our Unitholders, we will reimburse our General Partner for all expenses it has incurred on our behalf. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our General Partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to our Unitholders. Our General Partner has sole discretion to determine the amount of these expenses and fees.
In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our General Partner.

To the extent our General Partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our General Partner, our General Partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our Unitholders and cause the value of our Common Units to decline.
A reduction in ETP’s or Sunoco LP’s distributions will disproportionately affect the amount of cash distributions to which ETE is entitled.
ETE indirectly owns all of the IDRs of ETP and Sunoco LP. These IDRs entitle the holder to receive increasing percentages of total cash distributions made by each of ETP and Sunoco LP as such entity reaches established target cash distribution levels as specified in its partnership agreement. ETE currently receives its pro rata share of cash distributions from ETP and Sunoco LP based on the highest sharing level of 48% and 50% in respect of the ETP IDRs and Sunoco LP IDRs, respectively.
A decrease in the amount of distributions by ETP to ETE to less than $0.2638 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from ETP above $0.0958 per unit per quarter from 48% to 35%, and a decrease in the amount of distributions by Sunoco LP to ETE to less than $0.6563 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from Sunoco LP above $0.5469 per unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash distributions from the ETP or Sunoco LP would have the effect of disproportionately reducing the amount of all distributions that ETE and ETP receive, based on their ownership interest in the IDRs as compared to cash distributions they receive from their general partner interest and common units in such entity.
The consolidated debt level and debt agreements of ETP and Sunoco LP and those of their subsidiaries may limit the distributions we receive from ETP and Sunoco LP, as well as our future financial and operating flexibility.
ETP’s and Sunoco LP’s levels of indebtedness affect their operations in several ways, including, among other things:
a significant portion of ETP’s and Sunoco LP’s and their subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;
covenants contained in ETP’s and Sunoco LP’s and their subsidiaries’ existing debt agreements require ETP, Sunoco LP and their subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;
ETP’s and Sunoco LP’s and their subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
ETP and Sunoco LP may be at a competitive disadvantage relative to similar companies that have less debt;
ETP and Sunoco LP may be more vulnerable to adverse economic and industry conditions as a saleresult of their significant debt levels;
failure by ETP, Sunoco LP or their subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETP’s and Sunoco LP’s ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions to us and their unitholders.
We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt at maturity.
Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our Available Cash (as defined in our partnership agreement) to our Unitholders of record and our General Partner. Available Cash is generally all of our cash on hand as of the end of a quarter, adjusted for tax purposes, resultingcash distributions and net changes to reserves. Our General Partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries in $76 millionamounts it determines in its reasonable discretion to be necessary or appropriate:
to provide for the proper conduct of incremental income tax expense.

73
Tableour business and the businesses of Contents

Segment Operating Resultsour operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);
Investmentto provide funds for distributions to our Unitholders and our General Partner for any one or more of the next four calendar quarters; or
to comply with applicable law or any of our loan or other agreements.

A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.
A downgrade of our credit ratings might increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:
economic downturns;
deteriorating capital market conditions;
declining market prices for crude oil, natural gas, NGLs and other commodities;
terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Our subsidiaries are not prohibited from competing with us.
Neither our partnership agreement nor the partnership agreements of our subsidiaries, including ETP and Sunoco LP, prohibit our subsidiaries from owning assets or engaging in ETPbusinesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.
Capital projects will require significant amounts of debt and equity financing, which may not be available to ETP on acceptable terms, or at all.
 Years Ended December 31,  
 2014 2013 Change
Revenues$51,158
 $46,339
 $4,819
Cost of products sold45,540
 41,204
 4,336
Gross margin5,618
 5,135
 483
Unrealized gains on commodity risk management activities(23) (51) 28
Operating expenses, excluding non-cash compensation expense(1,640) (1,428) (212)
Selling, general and administrative expenses, excluding non-cash compensation expense(386) (396) 10
Inventory valuation adjustments473
 (3) 476
Adjusted EBITDA related to discontinued operations27
 76
 (49)
Adjusted EBITDA related to unconsolidated affiliates674
 629
 45
Other, net86
 (9) 95
Segment Adjusted EBITDA$4,829
 $3,953
 $876
ETP plans to fund its growth capital expenditures, including any new future pipeline construction projects and improvements or repairs to existing facilities that ETP may undertake, with proceeds from sales of ETP’s debt and equity securities and borrowings under its revolving credit facility; however, ETP cannot be certain that it will be able to issue debt and equity securities on terms satisfactory to it, or at all. In addition, ETP may be unable to obtain adequate funding under its current revolving credit facility because ETP’s lending counterparties may be unwilling or unable to meet their funding obligations. If ETP is unable to finance its expansion projects as expected, ETP could be required to seek alternative financing, the terms of which may not be attractive to ETP, or to revise or cancel its expansion plans.
Gross Margin. ForA significant increase in ETP’s indebtedness that is proportionately greater than ETP’s issuance of equity could negatively impact ETP’s credit ratings or its ability to remain in compliance with the year endedfinancial covenants under its revolving credit agreement, which could have a material adverse effect on ETP’s financial condition, results of operations and cash flows.
Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates. Approximately $9.86 billion of our consolidated debt as of December 31, 2014 compared2017 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates. We manage a portion of our interest rate exposures by utilizing interest rate swaps.
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment opportunities may cause the trading price of our Common Units to decline.
Unitholders may have liability to repay distributions.
Under certain circumstances, Unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law, will be liable to the prior year,limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to pay distributions to our Unitholders and to service our debt depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. If we are unable to obtain funds from our subsidiaries we may not be able to pay distributions to our Unitholders or to pay interest or principal on our debt when due.
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Our partnership agreement allows the general partner to incur obligations on our behalf that are expressly non-recourse to the general partner. The general partner has entered into such limited recourse obligations in most instances involving payment liability and intends to do so in the future.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Our debt level and debt agreements may limit our ability to make distributions to Unitholders and may limit our future financial and operating flexibility and may require asset sales.
As of December 31, 2017, we had approximately $6.70 billion of debt on a stand-alone basis and approximately $44.08 billion of consolidated debt, excluding the debt of our joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:
a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;
covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;
our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
we may be at a competitive disadvantage relative to similar companies that have less debt;
we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and
failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.
In order for us to manage our debt levels, we may need to sell assets, issue additional equity securities, reduce the cash distributions we pay to our unitholders or a combination thereof. In the event that we sell assets, the future cash generating capacity of our remaining asset base may be diminished. In the event that we issue additional equity securities, we may need to issue these securities at a time when our common unit price is depressed and therefore we may not receive favorable prices for our common units or favorable prices or terms for other types of equity securities. In the event we reduce cash distributions on our common units, the public trading price of our common units could decline significantly.
Our General Partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 90% of our outstanding units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2017, the directors and executive officers of our General Partner owned approximately 27% of our Common Units.

Litigation commenced by WMB against ETE and its affiliates could cause ETE to incur substantial costs, may present material distractions and, if decided adverse to ETE, could negatively impact ETE’s financial position and credit ratings.
WMB filed a complaint against ETE and its affiliates in the Delaware Court of Chancery, alleging that the defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates.  Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the merger agreement by ETE on June 29, 2016, WMB filed a notice of appeal to the Supreme Court of Delaware.  WMB filed an amended complaint on September 16, 2016 and seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement. The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by WMB’s misconduct. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that WMB breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, WMB filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on WMB’s motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.  On January 11, 2017, the parties held oral argument before the Delaware Supreme Court on WMB’s appeal of the June 24 ruling. The Delaware Supreme Court has taken the matter under advisement. These lawsuits could result in substantial costs to ETE, including litigation costs and settlement costs. ETE believes that the time required by the management of ETE and its counsel to defend against the allegations made by WMB in the litigation against ETE and its affiliates is likely to be substantial and the time required by the officers and employees of LE GP, assuming WMB actively pursues such litigation, is also likely to be substantial. The defense or settlement of any lawsuit or claim that remains unresolved may result in negative media attention, and may adversely affect ETE’s business, reputation, financial condition, results of operations, cash flows and market price.
Risks Related to Conflicts of Interest
Although we control ETP and Sunoco LP through our ownership of their general partners, ETP’s gross margin increased primarilyand Sunoco LP’s general partners owe fiduciary duties to ETP and ETP’s unitholders and Sunoco LP and Sunoco LP’s unitholders, respectively, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the following:relationships between us and our affiliates, on the one hand, and ETP and Sunoco LP and their respective limited partners, on the other hand. The directors and officers of ETP’s and Sunoco LP’s General Partners have fiduciary duties to manage ETP and Sunoco LP, respectively, in a manner beneficial to us. At the same time, the General Partners have fiduciary duties to manage ETP and Sunoco LP in a manner beneficial to ETP and Sunoco LP and their respective limited partners. The boards of directors of ETP’s and Sunoco LP’s General Partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.
Gross margin includedFor example, conflicts of interest with ETP and Sunoco LP may arise in the following situations:
the allocation of shared overhead expenses to ETP, Sunoco LP and us;
the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP and Sunoco LP, on the other hand;
the determination of the amount of cash to be distributed to ETP’s consolidatedand Sunoco LP’s partners and the amount of cash to be reserved for the future conduct of ETP’s and Sunoco LP’s businesses;
the determination whether to make borrowings under ETP’s and Sunoco LP’s revolving credit facilities to pay distributions to their respective partners;
the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of ETP and Sunoco LP is made available for ETP and Sunoco LP to pursue; and
any decision we make in the future to engage in business activities independent of ETP and Sunoco LP.

The fiduciary duties of our General Partner’s officers and directors may conflict with those of ETP’s or Sunoco LP’s respective general partners.
Conflicts of interest may arise because of the relationships among ETP, Sunoco LP, their general partners and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our General Partner’s directors are also directors and officers of ETP’s general partner or Sunoco LP’s general partner, and have fiduciary duties to manage the respective businesses of ETP and Sunoco LP in a manner beneficial to ETP, Sunoco LP and their respective Unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.
Potential conflicts of interest may arise among our General Partner, its affiliates and us. Our General Partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.
Conflicts of interest may arise among our General Partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:
Our General Partner is allowed to take into account the interests of parties other than us, including ETP and Sunoco LP and their respective affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.
Our General Partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
Our General Partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.
Our General Partner determines which costs it and its affiliates have incurred are reimbursable by us.
Our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.
Our General Partner controls the enforcement of obligations owed to us by it and its affiliates.
Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our partnership agreement limits our General Partner’s fiduciary duties to us and restricts the remedies available for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
provides that our General Partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit and Conflicts Committee of the board of directors of our General Partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
provides that unless our General Partner has acted in bad faith, the action taken by our General Partner shall not constitute a breach of its fiduciary duty;
provides that our General Partner may resolve any conflicts of interest involving us and our General Partner and its affiliates, and any resolution of a conflict of interest by our General Partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the partnership agreement;

provides that our General Partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the General Partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us; and
provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
The general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our Unitholders.
Our partnership agreement requires the general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, our partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.
Risks Related to the Businesses of our Subsidiaries
Since our cash flows consist exclusively of distributions from our subsidiaries, risks to the businesses of our subsidiaries are also risks to us. We have set forth below risks to the businesses of our subsidiaries, the occurrence of which could have a negative impact on their respective financial performance and decrease the amount of cash they are able to distribute to us.
ETP does not control, and therefore may not be able to cause or prevent certain actions by, certain of its joint ventures.
Certain of ETP’s joint ventures have their own governing boards, and ETP may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for ETP to cause the joint venture entity to take actions that ETP believes would be in their or the joint venture’s best interests. Likewise, ETP may be unable to prevent actions of the joint venture.
ETP and Sunoco LP are exposed to the credit risk of their respective customers and derivative counterparties, and an increase in the nonpayment and nonperformance by their respective customers or derivative counterparties could reduce their respective ability to make distributions to their Unitholders, including to us.
The risks of nonpayment and nonperformance by ETP’s and Sunoco LP’s respective customers are a major concern in their respective businesses. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP and Sunoco LP are subject to risks of loss resulting from nonpayment or nonperformance by their respective customers, especially during the current low commodity price environment impacting many oil and gas producers. As a result, the current commodity price volatility and the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s and Sunoco LP’s customers. To the extent one or more of our customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our Unitholders. Any substantial increase in the nonpayment and nonperformance by ETP’s or Sunoco LP’s customers could have a material adverse effect on ETP’s or Sunoco LP’s respective results of operations and operating cash flows.
The use of derivative financial instruments could result in material financial losses by ETP and Sunoco LP.
From time to time, ETP and Sunoco LP have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by their trading, marketing and/or system optimization activities. To the extent that either ETP or Sunoco LP hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change favorably. In addition, ETP’s and Sunoco LP’s derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to ETP’s retail marketing operations increased $471 million between periodsor Sunoco LP’s physical or financial positions, or internal hedging policies and procedures are not followed.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
In addition, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.
The inability to continue to access lands owned by third parties, including tribal lands, could adversely affect ETP’s and Sunoco LP’s ability to operate and adversely affect their financial results.
ETP’s ability to operate its pipeline systems and terminal facilities on certain lands owned by third parties, including lands held in trust by the United States for the benefit of a Native American tribe, will depend on their success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. Securing extensions of existing and any additional rights-of-way is also critical to ETP’s ability to pursue expansion projects. ETP cannot provide any assurance that they will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants or that all of the rights-of-way will be obtainable in a timely fashion. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively. ETP’s financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.
Further, whether ETP has the power of eminent domain for its pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state. In either case, ETP must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect ETP’s business if they were to lose the right to use or occupy the property on which their pipelines are located. For example, following a recent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. Any loss of rights with respect to ETP’s real property, through its inability to renew right-of-way contracts or otherwise, could have a material adverse effect on its business, results of operations, financial condition and ability to make cash distributions.
In addition, Sunoco LP does not own all of the land on which their retail service stations are located. Sunoco LP has rental agreements for approximately 35.2% of the company-operated retail service stations where Sunoco LP currently controls the real estate and has rental agreements for certain logistics facilities. As such, Sunoco LP is subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Sunoco LP is also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by Sunoco LP are leased from third parties for specific periods. Sunoco LP’s inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on its financial condition, results of operations and cash flows.
ETP and Sunoco LP may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.
ETP and Sunoco LP have strategies that contemplate growth through the development and acquisition of a wide range of midstream, retail and wholesale fuel distribution assets and other energy infrastructure assets while maintaining strong balance sheets. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP and Sunoco LP regularly consider and enter into discussions regarding the acquisition of Susseradditional assets and MACSbusinesses, stand-alone development projects or other transactions that ETP and Sunoco LP believe will present opportunities to realize synergies and increase cash flow.
Consistent with their strategies, managements of ETP and Sunoco LP may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP and Sunoco LP management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP and Sunoco LP believe it is the only party or one of a very limited number of potential buyers

in negotiations with the potential seller. We cannot assure that ETP’s or Sunoco LP’s acquisition efforts will be successful or that any acquisition will be completed on favorable fuel margins.terms.
Gross margin relatedIn addition, ETP and Sunoco LP are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETP or Sunoco LP losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s liquidsand Sunoco LP’s ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETP’s and Sunoco LP’s results of operations.
An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2017, our consolidated balance sheets reflected $4.77 billion of goodwill and $6.12 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.
During the fourth quarter of 2017, we performed goodwill impairment tests on our reporting units and recognized goodwill impairments at both ETP and Sunoco LP. The goodwill impairments at ETP consisted of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations increased $273and $452 million as a result of (i) increases in transportation margin as a result of higher volumes transported out of west Texas due to the completion expansion projects and (ii) higher processing and fractionation margin due to the completion of Lone Star’s fractionators in December 2013.
Gross margin from ETP’s midstreamits all other operations increased $79 million primarily due to an increasedecreases in fee-basedprojected future revenues and cash flows driven by increased production from assets recently placeddeclines in servicecommodity prices and changes in the Eagle Ford Shale.
markets that these assets serve. During the year 2017, Sunoco LP recorded a goodwill impairment charge of $102 million on its retail reporting unit.
These increases were partially offset by
During the following:
Revenue fromfourth quarter of 2016, we performed goodwill impairment tests on our reporting units and recognized goodwill impairments at both ETP and Sunoco LP. The goodwill impairments recognized at ETP consisted of $638 million related to ETP’s interstate transportation and storage operations and $32 million related to ETP’s midstream operations. These impairments are primarily due to decreases in projected future revenues and cash flows driven by reduced volumes as a result of overall declining commodity prices and changes in the markets that these assets serve. During the fourth quarter of 2016, Sunoco LP recognized a goodwill impairment of $641 million in its retail reporting unit primarily due to changes in assumptions related to projected future revenues and cash flows from the dates this goodwill was originally recorded. During the fourth quarter of 2016, Sunoco LP also recognized a $32 million impairment on its Laredo Taco brand name intangible asset primarily due to changes in Sunoco LP’s construction plan for new-to-industry sites and decreases in sales volume in oil field producing regions where Sunoco LP has operations.
If ETP and Sunoco LP do not make acquisitions on economically acceptable terms, their future growth could be limited.
ETP’s and Sunoco LP’s results of operations and their ability to grow and to increase distributions to Unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.
ETP and Sunoco LP may be unable to make accretive acquisitions for any of the following reasons, among others:
inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
inability to raise financing for such acquisitions on economically acceptable terms; or
inability to outbid by competitors, some of which are substantially larger than ETP or Sunoco LP and may have greater financial resources and lower costs of capital.
Furthermore, even if ETP or Sunoco LP consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP or Sunoco LP may:
fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;
significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;
encounter difficulties operating in new geographic areas or new lines of business;

incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which there is no indemnity or the indemnity is inadequate;
be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;
less effectively manage its historical assets, due to the diversion of management’s attention from other business concerns; or
incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
If ETP and Sunoco LP consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETP and Sunoco LP determine the application of their funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that ETP and Sunoco LP will consider.
Integration of assets acquired in past acquisitions or future acquisitions with our existing business will be a complex and time-consuming process. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to our unitholders.
The difficulties of integrating past and future acquisitions with our business include, among other things:
operating a larger combined organization in new geographic areas and new lines of business;
hiring, training or retaining qualified personnel to manage and operate our growing business and assets;
integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;
diversion of management’s attention from our existing business;
assimilation of acquired assets and operations, including additional regulatory programs;
loss of customers or key employees;
maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and
integrating new technology systems for financial reporting.
If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions resulting in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.
Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems, and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, may not be observable even when an inspection is undertaken.
Legal actions related to the Dakota Access Pipeline could cause an interruption to operations, which could have an adverse effect on our business and results of operations.
On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. The Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (the “Court”) against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline and claimed violations of the National Historic Preservation Act (“NHPA”). Dakota Access intervened in the case.
In February 2017, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. The SRST and Cheyenne River Sioux Tribe (“CRST”) (which had intervened in the lawsuit brought by SRST), amended their complaints to incorporate religious freedom and other claims related to treaties and use of government property. The Oglala and

Yankton Sioux tribes, and various individual members, filed related lawsuits in opposition to the Dakota Access pipeline. These lawsuits have been consolidated into the action initiated by the SRST.
On June 14, 2017, the Court ruled that the USACE substantially complied with all relevant statutes in connection with the issuance of the permits and easement, but remanded to the USACE three discrete issues for further analysis and explanation of its prior determination under certain of these statutes. On October 11, 2017, the Court ruled that the pipeline could continue to transport crude oil during the pendency of the remand, but requested briefing from the parties as to whether any conditions on the continued operation of the pipeline during this period. On December 4, 2017, the Court determined to impose three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. Second, the Court directed Dakota Access to continue its work with the tribes and the USACE to revise and finalize its response planning for the section of the pipeline crossing Lake Oahe. Third, the Court directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information recommended by PHMSA.
While we believe that the pending lawsuits are unlikely to adversely affect the continued operation of the pipeline, we cannot assure this outcome. At this time, we cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
In addition, lawsuits of this nature could result in interruptions to construction or operations of future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.
Income from ETP’s midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs and crude oil that are beyond our control.
The prices for natural gas, NGLs and crude oil (including refined petroleum products) reflect market demand that fluctuates with changes in global and United States economic conditions and other factors, including:
the level of domestic natural gas, NGL, and crude oil production;
the level of natural gas, NGL, and crude oil imports and exports, including liquefied natural gas;
actions taken by natural gas and oil producing nations;
instability or other events affecting natural gas and oil producing nations;
the impact of weather and other events of nature on the demand for natural gas, NGLs and crude oil;
the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;
the price, availability and marketing of competitive fuels;
the demand for electricity;
activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;
the cost of capital needed to maintain or increase production levels and to construct and expand facilities
the impact of energy conservation and fuel efficiency efforts; and
the extent of governmental regulation, taxation, fees and duties.
In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and we expect this volatility to continue.
Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs or crude oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGLs and crude oil commodities could materially affect our profitability.
ETP is affected by competition from other midstream, transportation and storage and retail marketing companies.
We experience competition in all of our business segments. With respect to ETP’s midstream operations, ETP competes for both natural gas supplies and customers for its services. Competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.
ETP’s natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas

and NGLs also compete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.
In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.
ETP’s crude oil and refined products pipeline operations face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in areas served by Sunoco Logistics’ pipelines. Further, our refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.
ETP may be unable to retain or replace existing midstream, transportation, terminalling and storagecustomers or volumes due to declining demand or increased competition in crude oil, natural gas and NGL markets, which would reduce revenues and limit future profitability.
The retention or replacement of existing customers and the volume of services that ETP provides at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of and demand for crude oil, natural gas, and NGLs in the markets we serve and competition from other service providers.
A significant portion of ETP’s sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in natural gas sales markets primarily on the basis of price.
ETP also receives a substantial portion of revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of their services are sold under long-term contracts for reserved service, they also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services, while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers’ business. If demand declines or competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.
Revenue from ETP’s NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. ETP receives substantially all of their transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to their transportation system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, ETP’s refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, a portion of its revenue is derived from fungible storage and throughput arrangements, under which ETP’s revenue is more dependent upon demand for storage from its customers.
The volume of crude oil and products transported through ETP’s oil pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. A period of sustained increases in the price of crude oil or products supplied from or delivered to any of these areas could materially reduce demand for crude oil or products in these areas. In either case, the volumes of crude oil or products transported in our oil pipelines and terminal facilities could decline.
The loss of existing customers by ETP’s midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services customers purchase from them, or their inability to attract new customers and service volumes would negatively affect revenues, be detrimental to growth, and adversely affect results of operations.

ETP’s midstream facilities and transportation pipelines are attached to basins with naturally declining production, which it may not be able to replace with new sources of supply.
In order to maintain or increase throughput levels on ETP’s gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, ETP must continually contract for new natural gas supplies and natural gas transportation services.
A substantial portion of ETP’s assets, including its gathering systems and processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. ETP’s gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. ETP may not be able to obtain additional contracts for natural gas supplies for its natural gas gathering systems, and may be unable to maintain or increase the levels of natural gas throughput on its transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to its transportation pipelines or markets to which ETP’s systems connect. ETP has no control over the level of drilling activity in its areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, ETP has no control over producers or their production and contracting decisions.
While a substantial portion of ETP’s services are provided under long-term contracts for reserved service, it also provides service on an unreserved basis. The reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities may decline and may not be replaced by other sources of supply. A decrease in development or production activity could cause a decrease in the volume of unreserved services ETP provides and a decrease in the number and volume of its contracts for reserved transportation service over the long run, which in each case would adversely affect revenues and results of operations.
If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.
The profitability of certain activities in ETP’s natural gas gathering, processing, transportation and storage operations is largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.
For a portion of the natural gas gathered on ETP’s systems, they purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where they typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins realized under these arrangements decrease in periods of low natural gas prices.
ETP also enters into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which they agree to gather and process natural gas received from the producers.
Under percent-of-proceeds arrangements, ETP generally sells the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, ETP delivers an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes kept to third parties at market prices. Under these arrangements, ETP’s revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on ETP’s revenues and results of operations.
Under keep-whole arrangements, ETP generally sells the NGLs produced from their gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, ETP must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.
When ETP processes the gas for a fee under processing fee agreements, they may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, ETP may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.
ETP also receives fees and retains gas in kind from natural gas transportation and storage customers. The fuel retention fees and the value of gas that ETP retains in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease these fuel retention fees and the value of retained gas.

In addition, ETP receives revenue from their off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of ETP’s off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for their off-gas processing and fractionation services and could have an adverse effect on their results of operations.
For ETP’s midstream operations, gross margin is generally analyzed based on fee-based margin (which includes revenues from processing fee arrangements) and non-fee based margin (which includes gross margin earned on percent-of-proceeds and keep-whole arrangements). For the years ended December 31, 2017, 2016 and 2015, gross margin from ETP’s midstream operations totaled $2.18 billion, $1.80 billion, and $1.79 billion, respectively, of which fee-based revenues constituted 78%, 86% and 88%, respectively, and non-fee based margin constituted 22%, 14% and 12%, respectively. The amount of gross margin earned by ETP’s midstream operations from fee-based and non-fee based arrangements (individually and as a percentage of total revenues) will be impacted by the volumes associated with both types of arrangements, as well as commodity prices; therefore, the dollar amounts and the relative magnitude of gross margin from fee-based and non-fee based arrangements in future periods may be significantly different from results reported in previous periods.
ETP’s revenues depend on its customers’ ability to use ETP’s pipelines and third-party pipelines over which we have no control.
ETP’s natural gas transportation, storage and NGL businesses depend, in part, on their customers’ ability to obtain access to pipelines to deliver gas to and receive gas from ETP. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third-party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material adverse effect on ETP’s ability, and the ability of their customers, to transport natural gas to and from their pipelines and facilities and a corresponding material adverse effect on their transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from ETP’s s facilities affect the utilization and value of their storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on storage revenues.
Shippers using ETP’s oil pipelines and terminals are also dependent upon their pipelines and connections to third-party pipelines to receive and deliver crude oil and products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in ETP’s pipelines or through their terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to ETP existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in their pipelines or through their terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on ETP’s results of operations, financial position, or cash flows.
If ETP does not continue to construct new pipelines, their future growth could be limited.
ETP’s results of operations and their ability to grow and to increase distributable cash flow per unit will depend, in part, on their ability to construct pipelines that are accretive to their respective distributable cash flow. ETP may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:
inability to identify pipeline construction opportunities with favorable projected financial returns;
inability to raise financing for its identified pipeline construction opportunities; or
inability to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.
Furthermore, even if ETP constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or fail to achieve results projected prior to commencement of construction.
Expanding ETP’s business by constructing new pipelines and related facilities subjects ETP to risks.
One of the ways that ETP has grown their business is through the construction of additions to existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline and related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond ETP’s control and requires the expenditure of significant amounts of capital to be financed through borrowings, the issuance of additional equity or from operating cash flow. If ETP undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. A variety of factors outside ETP’s control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors may result in increased costs or delays

in construction. Cost overruns or delays in completing a project could have a material adverse effect on ETP’s results of operations and cash flows. Moreover, revenues may not increase immediately following the completion of a particular project. For instance, if ETP builds a new pipeline, the construction will occur over an extended period of time, but ETP may not materially increase its revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, ETP may construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s expected investment return, which could adversely affect its results of operations and financial condition.
ETP depends on certain key producers for a significant portion of their supplies of natural gas. The loss of, or reduction in, any of these key producers could adversely affect ETP’s business and operating results.
ETP relies on a limited number of producers for a significant portion of their natural gas supplies. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, ETP will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. ETP may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on ETP’s business, results of operations, and financial condition.
ETP depends on key customers to transport natural gas through their pipelines.
ETP relies on a limited number of major shippers to transport certain minimum volumes of natural gas on their respective pipelines. The failure of the major shippers on ETP’s or their joint ventures’ pipelines or of other key customers to fulfill their contractual obligations under these contracts could have a material adverse effect on the cash flow and results of operations of us, ETP or their joint ventures, as applicable, were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
ETP’s contract compression operations depend on particular suppliers and are vulnerable to parts and equipment shortages and price increases, which could have a negative impact on results of operations.
The principal manufacturers of components for ETP’s natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers and Ariel Corporation for compressors and frames. ETP’s reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. ETP also relies primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble its compression units. ETP does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships.
A material decrease in demand or distribution of crude oil available for transport through ETP’s pipelines or terminal facilities could materially and adversely affect our results of operations, financial position, or cash flows.
The volume of crude oil transported through ETP’s crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by its assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to ETP’s customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in ETP’s crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all. If ETP is unable to replace any significant volume declines with additional volumes from other sources, its results of operations, financial position, or cash flows could be materially and adversely affected.
An interruption of supply of crude oil to ETP’s facilities could materially and adversely affect our results of operations and revenues.
While ETP is well positioned to transport and receive crude oil by pipeline, marine transport and trucks, rail transportation also serves as a critical link in the supply of domestic crude oil production to United States refiners, especially for crude oil from regions such as the Bakken that are not sourced near pipelines or waterways that connect to all of the major United States refining centers. Federal regulators have issued a safety advisory warning that Bakken crude oil may be more volatile than many other North American crude oils and reinforcing the requirement to properly test, characterize, classify, and, if applicable, sufficiently degasify hazardous materials prior to and during transportation. The domestic crude oil received by our facilities, especially from the Bakken region, may be transported by railroad. If the ability to transport crude oil by rail is disrupted because of accidents,

weather interruptions, governmental regulation, congestion on rail lines, terrorism, other third-party action or casualty or other events, then ETP could experience an interruption of supply or delivery or an increased cost of receiving crude oil, and could experience a decline in volumes received. Recent railcar accidents in Quebec, Alabama, North Dakota, Pennsylvania and Virginia, in each case involving trains carrying crude oil from the Bakken region, have led to increased legislative and regulatory scrutiny over the safety of transporting crude oil by rail. In 2015, the DOT, through the PHMSA, issued a rule implementing new rail car standards and railroad operating procedures. Changing operating practices, as well as new regulations on tank car standards and shipper classifications, could increase the time required to move crude oil from production areas of facilities, increase the cost of rail transportation, and decrease the efficiency of transportation of crude oil by rail, any of which could materially reduce the volume of crude oil received by rail and adversely affect our financial condition, results of operations, and cash flows.
A portion of ETP’s general and administrative services have been outsourced to third-party service providers. Fraudulent activity or misuse of proprietary data involving its outsourcing partners could expose us to additional liability.
ETP utilizes both affiliate entities and third parties in the processing of its information and data. Breaches of its security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about ETP or its customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose ETP to a risk of loss or misuse of this information, result in litigation and potential liability for ETP, lead to reputational damage, increase compliance costs, or otherwise harm its business.
Sunoco LP is entirely dependent upon third parties for the supply of refined products such as gasoline and diesel for its retail marketing business.
Sunoco LP is required to purchase refined products from third party sources, including the joint venture that acquired Sunoco, Inc.’s Philadelphia refinery. Sunoco LP may also need to contract for new ships, barges, pipelines or terminals which it has not historically used to transport these products to its markets. The inability to acquire refined products and any required transportation services at favorable prices may adversely affect Sunoco LP’s business and results of operations.
A significant decrease in demand for motor fuel, including increased consumer preference for alternative motor fuels or improvements in fuel efficiency, in the areas Sunoco LP serves would reduce their ability to make distributions to unitholders.
Sales of refined motor fuels account for approximately 93% of Sunoco LP’s total revenues and 62% of continuing operations gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and their ability to make or increase distributions to unitholders. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience declines in their profit margin if fuel distribution volumes decrease.
Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change customers' shopping habits or lead to new forms of fueling destinations or new competitive pressures.
New technologies have been developed and governmental mandates have been implemented to improve fuel efficiency, which may result in decreased $237 million primarilydemand for petroleum-based fuel. Any of these outcomes could result in fewer visits to Sunoco LP’s convenience stores or independently operated commission agents and dealer locations, a reduction in demand from their wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.

The industries in which Sunoco LP operates are subject to seasonal trends, which may cause our operating costs to fluctuate, affecting our cash flow.

Sunoco LP relies in part on customer travel and spending patterns, and may experience more demand for gasoline in the late spring and summer months than during the fall and winter. Travel, recreation and construction are typically higher in these months in the geographic areas in which Sunoco LP or its commission agents and dealers operate, increasing the demand for motor fuel that they sell and distribute. Therefore, Sunoco LP’s revenues and cash flows are typically higher in the second and third quarters of our fiscal year. As a result, Sunoco LP’s results from operations may vary widely from period to period, affecting Sunoco LP’s cash flow.

Sunoco LP’s financial condition and results of operations are influenced by changes in the prices of motor fuel, which may adversely impact margins, customers’ financial condition and the availability of trade credit.
Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.
Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.
The dangers inherent in the storage and transportation of motor fuel could cause disruptions in Sunoco LP’s operations and could expose them to potentially significant losses, costs or liabilities.
Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a material adverse effect on its business, financial condition, results of operations and cash available for distribution to unitholders.
Sunoco LP’s fuel storage terminals are subject to operational and business risks which may adversely affect their financial condition, results of operations, cash flows and ability to make distributions to unitholders.
Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following:
the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;
the dependence on third parties to supply their fuel storage terminals;
outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;
the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;
the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;
the effects of a sustained recession or other adverse economic conditions;
the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products;
competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and
climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.
The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s business, financial condition, results of operations, cash flows and ability to make distributions to unitholders.
Negative events or developments associated with Sunoco LP’s branded suppliers could have an adverse impact on its revenues.
Sunoco LP believes that the success of its operations is dependent, in part, on the continuing favorable reputation, market value, and name recognition associated with the motor fuel brands sold at Sunoco LP’s convenience stores and at stores operated by its independent, branded dealers and commission agents. Erosion of the value of those brands could have an adverse impact on the

volumes of motor fuel Sunoco LP distributes, which in turn could have a material adverse effect on its business, financial condition, results of operations and ability to make distributions to its unitholders.
The wholesale motor fuel distribution industry and convenience store industry are characterized by intense competition and fragmentation and impacted by new entrants. Failure to effectively compete could result in lower margins.
The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-added, reliable services and to control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.
The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently operated commission agents and dealers sell in stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.
In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse effect on its business, results of operations and cash available for distribution to unitholders.
Sunoco LP expect to generate a significant portion of its motor fuel sales under a fuel supply agreement with 7-Eleven, and any loss, or change in the economic terms, of such arrangement could adversely affect Sunoco LP’s business, financial condition and results of operations.
Sunoco LP expect that a significant portion of its motor fuel sales in 2018 will be derived from its fuel supply agreement with 7-Eleven. The 7-Eleven fuel supply agreement is a 15-year fixed margin, “take or pay” fuel supply arrangement with certain affiliates of 7-Eleven. The loss or change in economics of such arrangement and the inability to enter into new contracts on similar economically acceptable terms could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations.
Wholesale cost increases in tobacco products, including excise tax increases on cigarettes, could adversely impact Sunoco LP’s revenues and profitability.
Significant increases in wholesale cigarette costs and tax increases on cigarettes may have an adverse effect on unit demand for cigarettes. Cigarettes are subject to substantial and increasing excise taxes at both a state and federal level. Sunoco LP cannot predict whether this trend will continue into the future. Increased excise taxes may result in declines in overall sales volume and reduced gross profit percent, due to lower consumption levels and to a shift in consumer purchases from the premium to the non-premium or discount segments or to other lower-priced tobacco products or to the import of cigarettes from countries with lower, or no, excise taxes on such items.
Currently, major cigarette manufacturers offer rebates to retailers. Sunoco LP includes these rebates as a component of its gross margin from sales of cigarettes. In the event these rebates are no longer offered, or decreased, Sunoco LP’s wholesale cigarette costs will increase accordingly. In general, Sunoco LP attempts to pass price increases on to its customers. However, due to competitive pressures in our markets, it may not be able to do so. These factors could materially impact Sunoco LP’s retail price of cigarettes, cigarette unit volume and revenues, merchandise gross profit and overall customer traffic, which could in turn have a material adverse effect on Sunoco LP’s business and results of operations.

Failure to comply with state laws regulating the sale of alcohol and cigarettes may result in the loss of necessary licenses and the imposition of fines and penalties, which could have a material adverse effect on Sunoco LP’s business.
State laws regulate the sale of alcohol and cigarettes. A violation of or change in these laws could adversely affect Sunoco LP’s business, financial condition and results of operations because state and local regulatory agencies have the power to approve, revoke, suspend or deny applications for, and renewals of, permits and licenses relating to the sale of these products and can also seek other remedies. Such a loss or imposition could have a material adverse effect on Sunoco LP’s business and results of operations.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. A disruption in supply or a change in either relationship could have a material adverse effect on its business.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to unitholders.
Sunoco LP may be subject to adverse publicity resulting from concerns over food quality, product safety, health or other negative events or developments that could cause consumers to avoid its retail locations or independently operated commission agent or dealer locations.
Sunoco LP may be the subject of complaints or litigation arising from food-related illness or product safety which could have a negative impact on its business. Negative publicity, regardless of whether the allegations are valid, concerning food quality, food safety or other health concerns, food service facilities, employee relations or other matters related to its operations may materially adversely affect demand for its food and other products and could result in a decrease in customer traffic to its retail stores or independently operated commission agent or dealer locations.
It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name recognition.
Sunoco LP has outsourced various functions related to its retail marketing business to third-party service providers, which decreases its control over the performance of these functions. Disruptions or delays of its third-party outsourcing partners could result in increased costs, or may adversely affect service levels. Fraudulent activity or misuse of proprietary data involving its outsourcing partners could expose it to additional liability.
Sunoco LP has previously outsourced various functions related to its retail marketing business to third parties and expects to continue this practice with other functions in the future. While outsourcing arrangements may lower its cost of operations, they also reduce its direct control over the services rendered. It is uncertain what effect such diminished control will have on the quality or quantity of products delivered or services rendered, on its ability to quickly respond to changing market conditions, or on its ability to ensure compliance with all applicable domestic and foreign laws and regulations. Sunoco LP believes that it conducts appropriate due diligence before entering into agreements with its outsourcing partners. Sunoco LP relies on its outsourcing partners to provide services on a timely and effective basis. Although Sunoco LP continuously monitor the performance of these third parties and maintain contingency plans in case they are unable to perform as agreed, it does not ultimately control the performance of its outsourcing partners. Much of its outsourcing takes place in developing countries and, as a result, may be subject to geopolitical uncertainty. The failure of one or more of its third-party outsourcing partners to provide the expected services on a timely basis at the prices Sunoco LP expect, or as required by contract, due to events such as regional economic, business, environmental or political events, information technology system failures, or military actions, could result in significant disruptions and costs to its operations, which could materially adversely affect its business, financial condition, operating results and cash flow. Sunoco LP’s failure to generate significant cost savings from these outsourcing initiatives could adversely affect its profitability and weaken its competitive position. Additionally, if the implementation of its outsourcing initiatives is disruptive to its retail marketing business, Sunoco LP could experience transaction errors, processing inefficiencies, and the loss of sales and customers, which could cause its business and results of operations to suffer. As a result of these outsourcing initiatives, more third parties are involved in processing its retail marketing information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about its retail marketing business or its clients, including the potential loss or disclosure of such information or data as a result of fraud or other forms of

deception, could expose it to a risk of loss or misuse of this information, result in litigation and potential liability for it, lead to reputational damage to the Sunoco brand, increase its compliance costs, or otherwise harm its business.
ETP’s interstate natural gas pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.
Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of ETP’s interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.
ETP is required to file tariff rates (also known as recourse rates) with the FERC that shippers may elect to pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. ETP must also file with the FERC all negotiated rates that do not conform to our tariff rates and all changes to our tariff or negotiated rates. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.
The FERC may review existing tariff rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against ETP and find that its rates were not just and reasonable or unduly discriminatory, the maximum rates customers could elect to pay ETP may be reduced and the reduction could have an adverse effect on our revenues and results of operations.
The costs of ETP’s interstate pipeline operations may increase and ETP may not be able to recover all of those costs due to FERC regulation of its rates. If ETP proposes to change its tariff rates, its proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit ETP’s proposed changes if ETP is unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. ETP also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or ETP may be constrained by competitive factors from charging their tariff rates.
To the extent ETP’s costs increase in an amount greater than its revenues increase, or there is a lag between its cost increases and ability to file for and obtain rate increases, ETP’s operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. ETP cannot guarantee that its interstate pipelines will be able to recover all of their costs through existing or future rates.
The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. It is currently the FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, to the extent that the ultimate owners have an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Under the FERC’s policy, ETP thus remains eligible to include an income tax allowance in the tariff rates ETP charges for interstate natural gas transportation. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC issued the Notice of Inquiry in response to a remand from the United States Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect to the notice of inquiry ended on April 7, 2017. The outcome of the inquiry is still pending. ETP cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as part of a master limited partnership or decreases the return on equity for such pipelines could result in an adverse impact on ETP’s revenues associated with the transportation and storage services ETP provides pursuant to cost-based rates.
Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. Following the 2017 Tax Cuts and Jobs Act being signed into law, filings have been made at FERC requesting that FERC require pipelines to lower their transportation rates to account for lower taxes. Following the effective date of the law, the FERC orders granting certificates to construct proposed pipeline facilities have directed pipelines proposing new rates for service on those facilities to re-file such rates so that the rates reflect the reduction in the corporate tax rate, and

FERC has issued data requests in pending certificate proceedings for proposed pipeline facilities requesting pipelines to explain the impacts of the reduction in the corporate tax rate on the rate proposals in those proceedings and to provide re-calculated initial rates for service on the proposed pipeline facilities. FERC may enact other regulations or issue further requests to pipelines regarding the impact of the corporate tax rate change on the rates. The FERC’s establishment of a just and reasonable rate is based on many components, and the reduction in the corporate tax rate may impact two of such components: the allowance for income taxes and the amount for accumulated deferred income taxes. Because ETP’s existing jurisdictional rates were established based on a higher corporate tax rate, FERC or ETP’s shippers may challenge these rates in the future, and the resulting new rate may be lower than the rates ETP currently charges.
ETP’s interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect its business and operations.
In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of ETP’s interstate natural gas pipelines, including:
operating terms and conditions of service;
the types of services interstate pipelines may or must offer their customers;
construction of new facilities;
acquisition, extension or abandonment of services or facilities;
reporting and information posting requirements;
accounts and records; and
relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
Compliance with these requirements can be costly and burdensome. In addition, ETP cannot guarantee that the FERC will authorize tariff changes and other activities it might propose to undertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof may impair the ability of ETP’s interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.
The current FERC Chairman announced in December 2017 that FERC will review its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. ETP is unable to predict what, if any, changes may be proposed that will affect its natural gas pipeline business or when such proposals, if any, might become effective. ETP does not expect that any change in this policy would affect them in a materially different manner than any other similarly sized natural gas pipeline company operating in the United States.
Rate regulation or market conditions may not allow ETP to recover the full amount of increases in the costs of its crude oil, NGL and products pipeline operations.
Transportation provided on ETP’s common carrier interstate crude oil, NGL and products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If ETP proposes new or changed rates, the FERC or interested persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The primary ratemaking methodology used by the FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. The FERC’s ratemaking methodologies may limit our ability to set rates based on our costs or may delay the use of rates that reflect increased costs. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior two years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules ended March 17, 2017. FERC has not yet taken any further action on the proposed rule. If the FERC’s indexing methodology changes, the new methodology could materially and adversely affect our financial condition, results of operations or cash flows.

Under the EPAct of 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.
If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.
State regulatory measures could adversely affect the business and operations of ETP’s midstream and intrastate pipeline and storage assets.
ETP’s midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects their business and the market for their products. The rates, terms and conditions of service for the interstate services they provide in their intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. ETP’s HPL System, East Texas pipeline, Oasis pipeline and ET Fuel System provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than ETP’s costs of service, their cash flow would be negatively affected.
ETP’s midstream and intrastate gas and oil transportation pipelines and their intrastate gas storage operations are subject to state regulation. All of the states in which they operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which ETP operates have ratable take statutes, which generally require gatherers to take, without undue discrimination, production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, ETP’s businesses may be adversely affected.
ETP’s intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the TRRC. Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.
ETP is subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations of state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.
Certain of ETP’s assets may become subject to regulation.
The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of extensive litigation and may be determined by the FERC on a case-by-case basis, although the FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.
Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Lone Star’s NGL Pipeline transports NGLs within the state of Texas and is subject to regulation by the TRRC. This NGLs transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. In 2013, Lone Star’s NGL pipeline also commenced the interstate transportation of NGLs, which is subject to FERC’s jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992. Both intrastate and interstate NGL transportation services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a negotiated agreement; however, if FERC’s ratemaking methodologies were imposed, they may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the rates, terms and conditions for shipments of crude oil, petroleum products and NGLs on our pipelines are subject to regulation by FERC if the NGLs are transported in interstate or foreign commerce, whether by our pipelines or other means of transportation.

Since we do not control the entire transportation path of all crude oil, petroleum products and NGLs on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
In addition, if any of our pipelines were found to have provided services or otherwise operated in violation of the NGA, NGPA, or ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to these assets.
ETP may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to authority under the NGPSA and HLPSA, as amended, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect HCAs which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas.
These regulations require operators of covered pipelines to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline operations that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the deconsolidatedpipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, in January 2017, PHMSA issued a final rule for hazardous liquid pipelines that significantly expands the reach of certain PHMSA integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a HCA. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register is uncertain given the recent change in Presidential Administrations. In a second example, in April 2016, PHMSA published a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressure (“MOAP”); and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements and also require consideration of seismicity in evaluating threats to pipelines. The changes adopted or proposed by these rulemakings or made in future legal requirements could have a material adverse effect on ETP’s results of operations and costs of transportation services.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
The NGPSA and HLPSA were amended by the 2011 Pipeline Safety Act. Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the MAOP of certain interstate natural gas transmission pipelines. Effective April 27, 2017, maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $209,002 per day, with a maximum of $2,090,022 for a series of violations. In June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural

gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of natural gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as further amended by the 2016 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require ETP to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in ETP incurring increased operating costs that could be significant and have a material adverse effect on ETP’s results of operations or financial condition.
ETP’s business involves the generation, handling and disposal of hazardous substances, hydrocarbons and wastes, which activities are subject to environmental and worker health and safety laws and regulations that may cause ETP to incur significant costs and liabilities.
ETP’s business is subject to stringent federal, tribal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit, or prevent emissions, discharges or releases of various materials from ETP’s pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from ETP’s construction and operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective obligations, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property and natural resource damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or wastes into the environment.
ETP may incur substantial environmental costs and liabilities because of the underlying risk arising out of its operations. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation costs, liabilities or natural resource damages that could substantially increase our costs for site remediation projects. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.
Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on ETP’s operations or financial position. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to ETP’s customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new emission controls on some of ETP’s equipment, result in longer permitting timelines or new restrictions or prohibitions with respect to permits or projects, and significantly increase its capital expenditures and operating costs, which could adversely impact its business. Historically, ETP has been able to satisfy the more stringent nitrogen oxide emission reduction requirements that affect its compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that it will not incur material costs in the future to meet the new, more stringent ozone standard.
Product liability claims and litigation could adversely affect our subsidiaries business and results of operations.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.

Along with other refiners, manufacturers and sellers of gasoline, Sunoco, Inc. is a defendant in numerous lawsuits that allege methyl tertiary butyl ether (“MTBE”) contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to Sunoco, Inc. An adverse determination of liability related to these allegations or other product liability claims against Sunoco, Inc. could have a material adverse effect on our business or results of operations.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the services we provide.
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting "best available control technology" standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, the Subpart OOOOa standards have been subject to attempts by the EPA to stay portions of those standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. This rule, should it remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to ETP’s operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect ETP’s business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the United States State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on ETP’s business, financial condition, demand for its services, results of operations, and cash flows. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded

that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on ETP’s assets.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative instruments to mitigate the risks of changes in commodity prices and interest rates and other risks associated with our business.
Provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and rules adopted by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other prudential regulators establish federal regulation of the physical and financial derivatives, including over-the-counter derivatives market and entities, such as us, participating in that market. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, any new regulations or modifications to existing regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability and/or liquidity of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.
The CFTC has re-proposed speculative position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limits rule and its finalized companion rule on aggregation may create additional implementation or operational exposure. In addition to the CFTC federal speculative position limit regime, designated contract markets (“DCMs”) also maintain speculative position limit and accountability regimes with respect to contracts listed on their platform as well as aggregation requirements similar to the CFTC’s final aggregation rule. Any speculative position limit regime, whether imposed at the federal-level or at the DCM-level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.
The Dodd-Frank Act requires that certain classes of swaps be cleared on a derivatives clearing organization and traded on a DCM or other regulated exchange, unless exempt from such clearing and trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The CFTC and prudential regulators have also adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for and rely upon an end-user exception from such clearing and margin requirements for the swaps we enter into to hedge our commercial risks. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.
A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s operations and otherwise materially adversely affect their cash flow.
Some of ETP’s operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas pipeline and other facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Virtually all of ETP’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.
If one or more facilities that are owned by ETP or that deliver natural gas or other products to ETP are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s cash available for paying distributions to its Unitholders, including us.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s financial position and results of operations, as applicable. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Terrorist attacks aimed at our facilities could adversely affect its business, results of operations, cash flows and financial condition.
The United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on ETP’s or Sunoco LP’s facilities or pipelines, those of their customers, or in some cases, those of other pipelines could have a material adverse effect on ETP’s or Sunoco LP’s business, financial condition and results of operations.
Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and other related restrictions arising after the Deepwater Horizon incident in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.
In recent years, the federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the United States Department of the Interior, have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.
In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural gas exploration and production operations conducted offshore by certain of ETP’s customers. For example, in April 2016, the BOEM published a proposed rule that would update existing air-emissions requirements relating to offshore oil and natural-gas activity on federal Outer Continental Shelf waters. However, in May 2017, Order 3350 was issued by the Department of the Interior Secretary Ryan Zinke, directing the BOEM to reconsider a number of regulatory initiatives governing oil and gas exploration in offshore waters, including, among other things, a cessation of all activities to promulgate the April 2016 proposed rulemaking (“Order 3350”). In an unrelated legal initiative, BOEM issued a Notice to Lessees and Operators (“NTL #2016-N01”) that became effective in September 2016 and imposes more stringent requirements relating to the provision of financial assurance to satisfy decommissioning obligations. Together with a recent re-assessment by BSEE in 2016 in how it determines the amount of financial assurance required, the revised BOEM-administered offshore financial assurance program that is currently being implemented is expected to result in increased amounts of financial assurance being required of operators on the OCS, which amounts may be significant. However, as directed under Order 3350, the BOEM has delayed implementation of NTL #2016-N01 so that it may reconsider this regulatory initiative and, currently, this NTL’s implementation timeline has been extended indefinitely beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The April 2016 proposed rule and NTL #2016-N01, should they be finalized and/or implemented, as well as any new rules, regulations, or legal initiatives could delay or disrupt our customers operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to incur penalties, or shut-in production or lease cancellation. Also, if material spill events were to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities offshore and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development. The overall costs imposed on ETP’s customers to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete. We cannot predict with any certainty the full impact of any new laws or regulations on ETP’s customers’ drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. The occurrence of any one or more of these developments could result in decreased demand for ETP’s services, which could have a material adverse effect on its business as well as its financial position, results of operation and liquidity.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.
The petroleum products that we store and transport through ETP’s operations are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
In addition, our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.
Our business could be affected adversely by union disputes and strikes or work stoppages by Panhandle’s and Sunoco LP’s unionized employees.
As of December 31, 2017, approximately 5% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that Panhandle or Sunoco, Inc. will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.
Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, have a significant impact on our retail marketing business.
Federally mandated standards for use of renewable biofuels, such as ethanol and biodiesel in the production of refined products, are transforming traditional gasoline and diesel markets in North America. These regulatory mandates present production and logistical challenges for both the petroleum refining and ethanol industries, and may require us to incur additional capital expenditures or expenses particularly in our retail marketing business. We may have to enter into arrangements with other parties to meet our obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits. There also will be compliance costs related to these regulations. We may experience a decrease in demand for refined petroleum products due to new federal requirements for increased fleet mileage per gallon or due to replacement of refined petroleum products by renewable fuels. In addition, tax incentives and other subsidies making renewable fuels more competitive with refined petroleum products may reduce refined petroleum product margins and the ability of refined petroleum products to compete with renewable fuels. A structural expansion of production capacity for such renewable biofuels could lead to significant increases in the overall production, and available supply, of gasoline and diesel in markets that we supply. In addition, a significant shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel, or otherwise, also could lead to a decrease in demand, and reduced margins, for the refined petroleum products that we market and sell.
It is possible that any, or a combination, of these occurrences could have a material adverse effect on Sunoco, Inc.’s business or results of operations.
Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.
Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.

Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.
Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-today operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.
The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results.
Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership’s future consolidated financial results. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Partnership’s regulated businesses, the Partnership’s subsidiaries may not recover all of the costs and those rates are generally not immediately responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.
Mergers among customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of our systems in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.
The liquefaction project is dependent upon securing long-term contractual arrangements for the off-take of LNG on terms sufficient to support the financial viability of the project
LCL, an entity whose parent is owned 60% by ETE and 40% by ETP, is in the process of developing a liquefaction project at the site of ETE’s existing regasification facility in Lake Charles, Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc (now "Shell") related to this project expired in February 2017. On June 28, 2017, LCL signed a memorandum of understanding with Korea Gas Corporation and Shell to study the feasibility of a joint development of the Lake Charles liquefaction project. The project would utilize existing dock and storage facilities owned by ETE located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia).  Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.

The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or revocation.
While LCL has received authorization from the DOE to export LNG to non-FTA countries, the non-FTA authorization is subject to review, and the DOE may impose additional approval and permit requirements in the future or revoke the non-FTA authorization should the DOE conclude that such export authorization is inconsistent with the public interest.  The failure by LCL to timely maintain the approvals necessary to complete and operate the liquefaction project could have a material adverse effect on its operations and financial condition.
Sunoco LP is subject to federal laws related to the Renewable Fuel Standard.
New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make additional capital expenditures or incur additional liabilities. For example, certain independent refiners have initiated discussions with the EPA to change the way the Renewable Fuel Standard (RFS) is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers are obligated to obtain renewable identification numbers (“RINS”) either by blending biofuel into gasoline or through purchase in the open market. If the obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have to utilize the RINS it obtains through its blending activities to satisfy a new obligation and would be unable to sell RINS to other obligated parties, which may cause an impact on the fuel margins associated with Sunoco LP’s sale of gasoline.
The occurrence of any of the events described above could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
Sunoco LP is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers.
Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities, including commodities that Sunoco LP distributes. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce Sunoco LP’s ability to procure product, require it to incur additional handling costs and/or require the expenditure of capital. If Sunoco LP is unable to procure product or recover these costs through increased selling price, it may not be able to meet its financial obligations. Failure to comply with these regulations could result in substantial penalties for Sunoco LP.
The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements.
Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of corporations that are subject to all of the corporate governance requirements of the applicable stock exchange.
Tax Risks to Unitholders
Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us, ETP or Sunoco LP as a corporation for federal income tax purposes or if we, ETP or Sunoco LP become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investments in ETP and Sunoco LP depend largely on ETP and Sunoco LP being treated as partnerships for federal income tax purposes. Despite the fact that we, ETP and Sunoco LP are each a limited partnership under Delaware law, we would each be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we, ETP and Sunoco LP satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us, ETP or Sunoco LP to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we, ETP or Sunoco LP were treated as a corporation, we would pay federal income tax at the corporate tax rate and we would likely pay additional state income taxes at varying rates. Distributions to Unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to Unitholders. Because a tax would then be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Therefore,

treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of our Common Units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our Unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or to additional taxation as an entity for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing United States federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for United States federal income tax purposes.
In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for United States federal income tax purposes.
However, any modification to the United States federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for United States federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
If the IRS contests the federal income tax positions we take, the market for our Common Units may be adversely affected and the costs of any such contest will reduce cash available for distributions to our Unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us reducing the cash available for distribution to our Unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our Unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each Unitholder and former Unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our Unitholders and former Unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current Unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such Unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our Unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which will be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.
Tax gain or loss on disposition of our Common Units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income the unitholder was allocated for a unit, which decreased their tax basis in that unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to Unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be “unrelated business taxable income” and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.
Non-United States Unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.
Non-United States unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a United States trade or business.  As a result, distributions to a Non-United States unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-United States unitholder who sells or otherwise disposes of a unit will also be subject to United States federal income tax on the gain realized from the sale or disposition of that unit. 
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-United States unitholder’s sale or exchange of an interest in a partnership that is engaged in a United States trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges.  It is not clear if or when such regulations or other guidance will be issued.  Non-United States unitholders should consult a tax advisor before investing in our units.
We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
Even though we (as a partnership for United States federal income tax purposes) are not subject to United States federal income tax, some of our operations are conducted through subsidiaries that are organized as corporations for United States federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for United States federal income tax purposes, is subject to corporate-level United States federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the Common Units.
Because we cannot match transferors and transferees of Common Units and because of other reasons, we have adopted depreciation, depletion and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units and could have a negative impact on the value of our Common Units or result in audit adjustments to tax returns of our Unitholders. Moreover, because we have subsidiaries that are organized as C corporations for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having a greater tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our Unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, and if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
A Unitholder whose units are the subject of a securities loan (e.g. a loan to a “short seller”) to cover a short sale of units may be considered as having disposed of those units. If so, the Unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a Unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the Unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the Unitholder and any cash distributions received by the Unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies in determining Unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.
In addition to federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or our subsidiaries conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. We currently own property or conduct business in many states, most of which impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, our unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. Although the interest limitation does not apply to certain regulated pipeline businesses, application of the interest limitation to tiered businesses like ours that hold interests in regulated and unregulated businesses is not clear. Pending further guidance specific to this issue, we have not yet determined the impact the limitation could have on our unitholders’ ability to deduct our interest expense, but it is possible that our unitholders’ interest expense deduction will be limited.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
A description of our properties is included in “Item 1. Business.” In addition, we own office buildings for our executive offices in Dallas, Texas and office buildings in Newton Square, Pennsylvania and Houston, Corpus Christi and San Antonio, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.
Substantially all of our subsidiaries’ pipelines, which are described in “Item 1. Business,” are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. Our subsidiaries have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our subsidiaries’ pipelines were built were purchased in fee. ETP also owns and operates multiple natural gas and NGL storage facilities and owns or leases other processing, treating and conditioning facilities in connection with its midstream operations.
ITEM 3. LEGAL PROCEEDINGS
Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2017, Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico.

The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland.
Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
In January 2012, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas.  The proposed penalties are in excess of $100,000. The case went to hearing in November 2016 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $52$100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.
In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In December 2016, we received multiple Notice of Violations (“NOVs”) from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at our Marcus Hook Industrial Complex (“MHIC”) in July 2016. We also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to our tank inspection plan at MHIC.  These actions propose penalties in excess of $100,000, and we are currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows, or financial position.
The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of the Rover pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April 2017 to July 2017. Although Rover has successfully completed clean-up mitigation for the alleged violations to Ohio EPA’s satisfaction, the Ohio EPA has proposed penalties of approximately $2.6 million received in connection with the buyoutalleged violations and is seeking certain injunctive relief. The Ohio Attorney General filed a complaint in the Court of Common Pleas of Stark County, Ohio to obtain these remedies and that case remains pending and is in the early stages. The timing or outcome of this matter cannot be reasonably

determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. In response, FERC authorized Rover to resume HDD activities at certain sites. On January 24, 2018, FERC ordered Rover to cease HDD activities at the Tuscarawas River HDD site pending FERC review of additional information from Rover. Rover continues to correspond with regulators regarding drilling operations and drilling plans at the HDD sites where Rover has not yet completed HDD activities, including the Tuscarawas River HDD site. The timing or outcome of this matter cannot be reasonably determined at this time. We do not expect there to be a material impact to its results of operations, cash flows or financial position.
In late 2016, FERC Enforcement Staff began a non-public investigation of Rover’s demolition of the Stoneman House, a potential historic structure, in connection with Rover’s application for permission to construct a new interstate natural gas pipeline and related facilities.  Rover and ETP are cooperating with the investigation.  In March and April 2017, Enforcement Staff provided Rover its non-public preliminary findings regarding its investigation.  The company disagrees with those findings and intends to vigorously defend against any potential penalty. Given the stage of the proceeding, and the non-public nature of the preliminary findings and investigation, ETP is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.
On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project.  The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”).  On August 10, 2017 the parties reached a final settlement requiring that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation.  Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits.  Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.
In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project.  Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval.  SPLP is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
On January 18, 2018, PHMSA issued a NOPV and a Proposed Civil Penalty in connection with alleged violations on ETP’s East Boston jet fuel pipeline in Boston, MA. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
On January 18, PHMSA issued a NOPV and a PCO in connection with alleged violations on Eastern Area refined products and crude oil pipeline system in the States of MI, OH, PA, NY, NJ and DE. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed above were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report environmental governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $100,000.
For a description of other legal proceedings, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

PART II
ITEM 5.  MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Parent Company
Market Price of and Distributions on Common Units and Related Unitholder Matters
The Parent Company’s common units are listed on the NYSE under the symbol “ETE.” The following table sets forth, for the periods indicated, the high and low sales prices per ETE Common Unit, as reported on the NYSE Composite Tape, and the amount of cash distributions paid per ETE Common Unit for the periods indicated.
 Price Range 
Cash
Distribution (1)
 High Low 
Fiscal Year 2017:     
Fourth Quarter$18.71
 $15.64
 $0.3050
Third Quarter18.50
 16.18
 0.2950
Second Quarter19.82
 15.03
 0.2850
First Quarter20.05
 17.62
 0.2850
      
Fiscal Year 2016:     
Fourth Quarter$19.99
 $13.77
 $0.2850
Third Quarter19.44
 13.45
 0.2850
Second Quarter15.13
 6.40
 0.2850
First Quarter14.39
 4.00
 0.2850

(1)
Distributions are shown in the quarter with respect to which they relate. Please see “Cash Distribution Policy” below for a discussion of our policy regarding the payment of distributions.
Description of Units
As of February 16, 2018, there were approximately 158,922 individual common unitholders, which includes common units held in street name. Common units represent limited partner interest in us that entitle the holders to the rights and privileges specified in the Parent Company’s Third Amended and Restated Agreement of Limited Partnership, as amended to date (the “Partnership Agreement”).
As of December 31, 2017, limited partners own an aggregate 94.4% limited partner interest in us. Our General Partner owns an aggregate 0.2% General Partner interest in us. Our common units are registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and are listed for trading on the NYSE. Each holder of a customer contract.common unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all common units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The common units are entitled to distributions of Available Cash as described below under “Cash Distribution Policy.”
Gross marginOn March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on

a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.
The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 2017.
Cash Distribution Policy
General.  The Parent Company will distribute all of its “Available Cash” to its unitholders and its General Partner within 50 days following the end of each fiscal quarter.
Definition of Available Cash.Available Cash is defined in the Parent Company’s Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:
provide for the proper conduct of its business;
comply with applicable law and/or debt instrument or other agreement; and
provide funds for distributions to unitholders and its General Partner in respect of any one or more of the next four quarters.
Recent Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.
Securities Authorized for Issuance Under Equity Compensation Plans
For information on the securities authorized for issuance under ETE’s equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”
ITEM 6.  SELECTED FINANCIAL DATA
The selected historical financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in millions.
As discussed in Note 2 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data,” in the fourth quarter of 2017, ETP changed its accounting policy related to ETP’s intrastate transportationcertain inventories. Certain crude oil, refined product and storageNGL inventories were changed from last-in, first-out (“LIFO”) method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

 Years Ended December 31,
 2017 2016* 2015* 2014* 2013*
Statement of Operations Data:         
Total revenues$40,523
 $31,792
 $36,096
 $54,435
 $48,335
Operating income2,713
 1,843
 2,287
 2,389
 1,587
Income from continuing operations2,543
 462
 1,023
 1,014
 318
Income (loss) from discontinued operations(177) (462) 38
 60
 33
Net Income2,366
 —
 1,061
 1,010
 351
Basic income from continuing operations per limited partner unit0.86
 0.95
 1.11
 0.57
 0.17
Diluted income from continuing operations per limited partner unit0.84
 0.93
 1.11
 0.57
 0.17
Basic income (loss) from discontinued operations per limited partner unit(0.01) (0.01) —
 0.01
 0.01
Diluted income (loss) from discontinued operations per limited partner unit(0.01) (0.01) —
 0.01
 0.01
Cash distribution per common unit1.17
 1.14
 1.08
 0.80
 0.67
Balance Sheet Data (at period end):         
Assets held for sale3,313
 3,588
 3,681
 3,372
 —
Total assets(1)
86,246
 78,925
 71,144
 64,266
 50,367
Liabilities associated with assets held for sale75
 48
 42
 47
 —
Long-term debt, less current maturities43,671
 42,608
 36,837
 29,477
 22,562
Total equity29,980
 22,431
 23,553
 22,301
 16,341
*As adjusted for the change in accounting policy related to inventory valuation, as discussed above.
(1)
Includes assets held for sale
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts, except per unit data, are in millions)
Energy Transfer Equity, L.P. is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ETE.” ETE was formed in September 2002 and completed its initial public offering in February 2006.
The following is a discussion of our historical consolidated financial condition and results of operations, decreased $27 million primarilyand should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.
Unless the cessationcontext requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
OVERVIEW
Energy Transfer Equity, L.P. directly and indirectly owns equity interests in ETP and Sunoco LP, both publicly traded master limited partnerships engaged in diversified energy-related services.
The historical common units for ETP presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger, discussed in “Item 1. Business.”
At January 25, 2018, subsequent to Sunoco LP’s repurchase of long-term transportation contracts.
the 12 million Sunoco Logistics’ gross margin decreased $87 million primarily related to lower crude oil margins.
Unrealized Gains on Commodity Risk Management Activities. Unrealized gains on commodity risk management activities primarily reflectedLP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the net impact from unrealized gainsrespective general partner interests and losses on natural gas storage and non-storage derivatives,IDRs, as well as fair value adjustmentsapproximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to inventory. any distributions.

The decreaseParent Company’s principal sources of cash flow are derived from its direct and indirect investments in unrealized gains on commodity risk management activitiesthe limited partner and general partner interests in ETP and Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and the Partnership’s ownership of Lake Charles LNG. The Parent Company’s primary cash requirements are for 2014 compared to 2013 was primarily attributable to natural gas storage inventory and related derivatives.
Operating Expenses, Excluding Non-Cash Compensation Expense. Operating expenses related to ETP’s retail marketing operations increased $254 million, primarily due to recent acquisitions. In addition, Sunoco Logistics’ operating expenses increased $44 million, primarily due to lower pipeline operating gains, increased pipeline maintenance costs and higher employee costs. Operating expenses also increased $19 million for ETP’s liquids transportation and services operations, primarily due to the start-up of Lone Star’s second fractionator in Mont Belvieu, Texas in October 2013. These increases were partially offset by decreases in ETP’s operating expenses duedistributions to its deconsolidation of certain operations during the periods, including Lake Charles LNG effective January 1, 2014 and SUGS in April 2013.
Selling, General and Administrative Expenses, Excluding Non-Cash Compensation Expense. Selling,partners, general and administrative expenses, relateddebt service requirements and at ETE’s election, capital contributions to ETP’s retail marketingETP and Sunoco LP in respect of ETE’s general partner interests in ETP and Sunoco LP. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries.
In order to fully understand the financial condition and results of operations increased $29 million,of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.
General
Our primary objective is to increase the level of our distributable cash flow to our unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and liquids businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily due to recent acquisitions. In addition,

74
Tabledepend on the amount of Contentscash our subsidiaries generate from their operations.
Our reportable segments are as follows:

Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco Logistics’ selling, general and administrative expenses increased $28 million. Selling, general and administrative expenses also increased for ETP’s liquids transportation and servicesLP, including the consolidated operations due to higher employee-related costs. These increases were partially offset by decreasesof Sunoco LP;
Investment in ETP’s expenses due to its deconsolidation of certain operations during the periods, including Lake Charles LNG, effectiveincluding the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
Each of the respective general partners of ETP and Sunoco LP have separate operating management and boards of directors. We control ETP and Sunoco LP through our ownership of their respective general partners.
Recent Developments
ETE Senior Notes Offering
In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.
Sunoco LP Series A Preferred Units
On March 30, 2017, the Partnership purchased 12 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units was 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate would become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference.
In January 1, 20142018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and SUGSa 1% call premium plus accrued and unpaid quarterly distributions.
ETE January 2017 Private Placement and ETP Unit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in April 2013.the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units.
January 2018 Sunoco LP Common Units Repurchase
Adjusted EBITDA RelatedIn February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to Discontinued Operations. In 2014,repay amounts were related to a marketing business that was sold effective April 1, 2014. In 2013, amounts primarily related to Southern Union’s distribution operations.outstanding under its revolving credit facility.

CDM Contribution Agreement
Adjusted EBITDA RelatedIn January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to Unconsolidated Affiliates. ETP’s Adjusted EBITDA relatedwhich, among other things, ETP will contribute to unconsolidated affiliates for the years ended December 31, 2014USAC and 2013 consistedUSAC will acquire from ETP all of the following:issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.
In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million.
 Years Ended December 31,  
 2014 2013 Change
Citrus$305
 $296
 $9
FEP75
 75
 —
Regency100
 66
 34
PES86
 (30) 116
AmeriGas56
 175
 (119)
Other52
 47
 5
Total Adjusted EBITDA related to unconsolidated affiliates$674
 $629
 $45
ETP Credit Facilities
TheseOn December 1, 2017 ETP entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).
ETP Series A and Series B Preferred Units
In November 2017, ETP issued 950,000 of its 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit.
Distributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
ETP Senior Notes Offering
In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility and for general partnership purposes.
ETP August 2017 Units Offering
In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts represent ETP’s proportionateoutstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

Rover Contribution Agreement
In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Adjusted EBITDARover construction costs incurred by ETP through the closing date, along with the payment of its unconsolidated affiliatesadditional amounts subject to certain adjustments.
PennTex Tender Offer and are based on ETP’s equity in earnings or losses of its unconsolidated affiliates adjusted for its proportionate shareLimited Call Right Exercise
In June 2017, ETP purchased all of the unconsolidated affiliates’ interest, depreciation, amortization, non-cash itemsoutstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and taxes.PennTex common units are no longer publicly traded or listed on the NASDAQ.
Other.ETP and Sunoco Logistics Merger Other, net
In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in 2014 primarily includes amortizationwhich Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction, with the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of regulatorySunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.
Sunoco LP Private Offering of Senior Notes
On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing of the asset purchase agreement with 7-Eleven to: 1) redeem in full its existing senior notes as of December 31, 2017, comprised of $800 million in aggregate principal amount of 6.250% senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; 2) repay in full and terminate the Sunoco LP Term Loan; 3) pay all closing costs and taxes in connection with the 7-Eleven transaction; 4) redeem the outstanding Sunoco LP Series A Preferred Units as mentioned above; and 5) repurchase 17,286,859 common units owned by ETP as mentioned above.
Sunoco LP Convenience Store Sale
On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven (“SEI Fuel” and together with 7-Eleven, referred to herein collectively as “Buyers”). Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.3 billion.
Sunoco LP has signed definitive agreements with a commission agent to operate the approximately 207 retail sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the previously announced transaction with 7-Eleven, Inc. Conversion of these sites to the commission agent is expected to occur in the first quarter of 2018.
Sunoco LP Real Estate Sale
On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.
Permian Express Partners
In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois

terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and other income$435 million of property, plant and expense amounts. Other, netequipment.
In July 2017, ETP contributed an approximate 15% ownership interest in 2013 was primarily relatedDakota Access and ETCO to biodiesel tax credits recorded by Sunoco, Inc., amortizationPEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of regulatory assets and other income and expense amounts.
Investment in Regency
 Years Ended December 31,  
 2014 2013 Change
Revenues$4,951
 $2,521
 $2,430
Cost of products sold3,452
 1,793
 1,659
Gross margin1,499
 728
 771
Unrealized (gains) losses on commodity risk management activities(89) 9
 (98)
Operating expenses, excluding non-cash compensation expense(448) (296) (152)
Selling, general and administrative, excluding non-cash compensation expense(148) (81) (67)
Adjusted EBITDA related to unconsolidated affiliates325
 250
 75
Other, net33
 (2) 35
Segment Adjusted EBITDA$1,172
 $608
 $564
Gross Margin. Regency’s gross margin increased forall of the year ended December 31, 2014 compared to the prior year primarily due to increased volumes in Regency’s south and west Texas and north Louisiana gathering and processing operations, as wellassets. As such, PEP is reflected as a $434 million increase from the PVR, Eagle Rock and Hoover acquisitions.
Operating Expenses, Excluding Non-Cash Compensation Expense. Regency’s operating expenses reflected an increase of $76 million in pipeline and plant maintenance and materials expense primarily due to organic growth in south and west Texas, as well as recent acquisitions. In addition, Regency’s recent acquisitions also resulted in a $44 million increase in employee expenses and a $15 million increase in ad valorem taxes. The remainderconsolidated subsidiary of the increase was primarily duePartnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to higher insurance, professional feesMarEn Bakken Company LLC, an entity jointly owned by MPLX LP and communications expense.Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.

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Selling, General and Administrative, Excluding Non-Cash Compensation Expense. Regency’s selling, general and administrative expenses increased primarily due to acquisition costs of $33 million, as well as $30 million from increased employee headcount due to the PVR, Eagle rock and Hoover acquisitions.
Adjusted EBITDA Related to Unconsolidated Affiliates. Regency’s adjusted EBITDA related to unconsolidated affiliates increased $75 million primarily due to the impact from Lone Star.
Other. The change in Regency’s other income and deductions is primarily due to a non-cash mark-to-market adjustment of the embedded derivatives related to Regency’s Series A preferred units.
Investment in Lake Charles LNG
 Years Ended December 31,  
 2014 2013 Change
Revenues$216
 $216
 $—
Operating expenses, excluding non-cash compensation expense(17) (20) 3
Selling, general and administrative, excluding non-cash compensation expense(4) (9) 5
Segment Adjusted EBITDA$195
 $187
 $8
Amounts reflected above include comparative amounts for the year ended December 31, 2013, which preceded ETE’s direct investment in Lake Charles LNG effective January 1, 2014.
Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.

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Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012 (tabular dollar amounts are expressed in millions)
Consolidated Results
 Years Ended December 31,  
 2013 2012 Change
Segment Adjusted EBITDA:     
Investment in ETP$3,953
 $2,744
 $1,209
Investment in Regency608
 517
 91
Investment in Lake Charles LNG187
 135
 52
Corporate and Other(43) (52) 9
Adjustments and Eliminations(338) (239) (99)
Total4,367
 3,105
 1,262
Depreciation, depletion and amortization(1,313) (871) (442)
Interest expense, net of interest capitalized(1,221) (1,018) (203)
Bridge loan related fees—
 (62) 62
Gain on deconsolidation of Propane Business—
 1,057
 (1,057)
Gain on sale of AmeriGas common units87
 —
 87
Goodwill impairment(689) —
 (689)
Gains (losses) on non-hedged interest rate derivatives53
 (19) 72
Non-cash unit-based compensation expense(61) (47) (14)
Unrealized gains on commodity risk management activities48
 10
 38
Inventory valuation adjustments3
 (75) 78
Losses on extinguishments of debt(162) (123) (39)
Adjusted EBITDA related to discontinued operations(76) (99) 23
Adjusted EBITDA related to unconsolidated affiliates(727) (647) (80)
Equity in earnings of unconsolidated affiliates236
 212
 24
Non-operating environmental remediation(168) —
 (168)
Other, net(2) 14
 (16)
Income from continuing operations before income tax expense375
 1,437
 (1,062)
Income tax expense93
 54
 39
Income from continuing operations282
 1,383
 (1,101)
Income (loss) from discontinued operations33
 (109) 142
Net income$315
 $1,274
 $(959)
See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.
The year ended December 31, 2012 was impacted by multiple transactions. Additional information has been provided in “Supplemental Pro Forma Information” below, which provides pro forma information assuming the transactions had occurred at the beginning of the period.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily as a result of acquisitions and growth projects including:
depreciation and amortization related to Sunoco Logistics of $265 million in 2013 compared to $63 million from October 5, 2012 through December 31, 2012;
depreciation and amortization related to Sunoco, Inc. of $113 million in 2013 compared to $32 million from October 5, 2012 through December 31, 2012;

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depreciation and amortization related to Southern Union of $189 million in 2013 compared to $179 million from March 26, 2012 through December 31, 2012; and
additional depreciation, depletion and amortization recorded from assets placed in service in 2013 and 2012.
Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:
interest expense related to Sunoco Logistics of $76 million in 2013 compared to $14 million from October 5, 2012 through December 31, 2012;
interest expense related to Sunoco, Inc. of $33 million in 2013 compared to $9 million from October 5, 2012 through December 31, 2012;
incremental interest expense due to ETP’s issuance of $1.25 billion of senior notes in January 2013 and $1.5 billion of senior notes in September 2013; and
an increase of $42 million related to Regency primarily due to its issuance of $700 million of senior notes in October 2012, $600 million of senior notes in April 2013 and $400 million of senior notes in September 2013; partially offset by
a reduction of $25 million for the Parent Company primarily related to a $1.1 billion principal paydown of the Parent Company’s $2 billion term loan in April 2013.
Bridge Loan Related Fees. The bridge loan commitment fee recognized during the year ended December 31, 2012 was incurred in connection with the Southern Union Merger. The Parent Company obtained permanent financing for the transaction through a $2 billion senior secured term loan which was funded upon closing of the Southern Union Merger on March 26, 2012.
Gain on Deconsolidation of Propane Business. ETP recognized a gain on deconsolidation related to the contribution of its Propane Business to AmeriGas in January 2012.
Gain on Sale of AmeriGas Common Units. In July 2013, ETP sold 7.5 million of the AmeriGas common units that ETP originally received in connection with the contribution of its Propane Business to AmeriGas in January 2012. ETP recorded a gain based on the sale proceeds in excess of the carrying amount of the units sold.
Goodwill Impairment. In 2013, Lake Charles LNG recorded a $689 million goodwill impairment. See additional discussion in the analysis of consolidated results for the year ended December 31, 2014 compared to the year ended December 31, 2013.
Gains (Losses) on Interest Rate Derivatives. Gains on interest rate derivatives during the year ended December 31, 2013 resulted from increases in forward interest rates, which caused our forward-starting swaps to increase in value. These swaps are marked to fair value for accounting purposes with changes in value recorded in earnings each period. Conversely, decreases in forward interest rates resulted in losses on interest rate derivatives during the year ended December 31, 2012.
Unrealized Gains on Commodity Risk Management Activities. See discussion of the unrealized gains on commodity risk management activities included in the discussion of segment results below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with ETP’s retail marketing operations as a result of commodity price changes between periods.
Losses on Extinguishments of Debt. For the year ended December 31, 2013, the loss on extinguishment of debt was primarily related to ETE’s refinancing transactions completed in December 2013. For the year ended December 31, 2012, ETP recognized a loss on extinguishment of debt in connection with its repurchase of approximately $750 million in aggregate principal amount of senior notes in January 2012. In addition, Regency recognized a $7 million loss on extinguishment of debt in connection with its repurchase of senior notes in June 2013 and an $8 million loss in connection with its repurchases of senior notes in May 2012.
Adjusted EBITDA Related to Discontinued Operations. For the year ended December 31, 2013, amounts reflected Southern Union’s distribution operations through the date of sale. Southern Union completed the sales of the assets of MGE in September 2013 and the assets of NEG in December 2013. For the year ended December 31, 2012, amounts reflected the operations of Canyon, which was sold in October 2012, and, for the period from March 26, 2012 to December 31, 2012, Southern Union’s distribution operations. See additional discussion of results in “Segment Operating Results” below.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. Amounts reflected primarily include our proportionate share of such amounts related to AmeriGas, FEP, HPC and MEP, as well as Citrus beginning March 26, 2012. See additional discussion of results in “Segment Operating Results” below.

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Non-Operating Environmental Remediation. Non-operating environmental remediation was primarily related to Sunoco, Inc.’s recognition of environmental obligations related to closed sites.
Other, net. Includes amortization of regulatory assets and other income and expense amounts.
Income Tax Expense from Continuing Operations. Income tax expense increased primarily due to the acquisitions of Southern Union and Sunoco, Inc. in 2012, both of which are taxable corporations.
Segment Operating Results
Investment in ETP
 Years Ended December 31,  
 2013 2012 Change
Revenues$46,339
 $15,702
 $30,637
Cost of products sold41,204
 12,266
 28,938
Gross margin5,135
 3,436
 1,699
Unrealized (gains) losses on commodity risk management activities(51) 9
 (60)
Operating expenses, excluding non-cash compensation expense(1,428) (947) (481)
Selling, general and administrative, excluding non-cash compensation expense(396) (408) 12
Inventory valuation adjustments(3) 75
 (78)
Adjusted EBITDA related to discontinued operations76
 99
 (23)
Adjusted EBITDA related to unconsolidated affiliates629
 480
 149
Other, net(9) —
 (9)
Segment Adjusted EBITDA$3,953
 $2,744
 $1,209
Gross Margin. For the year ended December 31, 2013 compared to the prior year, ETP’s gross margin increased primarily as a result of the net impact of the following:
The year ended December 31, 2013 reflected a full year of operations of Sunoco Logistics and ETP’s retail marketing operations which were acquired October 5, 2012. Gross margin included in our consolidated results related to Sunoco Logistics and ETP’s retail marketing operations increased $761 million and $693 million, respectively, between periods.
Revenues from ETP’s interstate transportation and storage operations increased $200 million primarily as a result of ETP’s consolidation of Southern Union’s transportation and storage operations beginning March 26, 2012 and the recognition of $52 million received in connection with the buyout of a Southern Union customer’s contract.
Gross margin related to ETP’s liquids transportation and services operations increased $183 million as a result of (i) increases in transportation margin as a result of higher volumes transported out of West Texas due to the completion expansion projects and (ii) higher processing and fractionation margin due to the completion of Lone Star’s fractionators in December 2012 and December 2013.
These increases were partially offset by a decrease of $82 million in gross margin related to ETP’s intrastate transportation and storage operations primarily due to the cessation of long-term transportation contracts.
These increases were further offset by a decrease of $10 million in gross margin related to ETP’s midstream operations primarily related to the deconsolidation of SUGS.
Unrealized (Gains) Losses on Commodity Risk Management Activities. Unrealized (gains) losses on commodity risk management activities primarily reflected the net impact from unrealized gains and losses on natural gas storage and non-storage derivatives, as well as fair value adjustments to inventory. The increase in unrealized gains on commodity risk management activities for 2013 compared to 2012 was primarily attributable to natural gas storage inventory and related derivatives.
Operating Expenses, Excluding Non-Cash Compensation Expense. For the year ended December 31, 2013 compared to the prior year, ETP’s operating expense increased primarily as a result of a full year of operations related to Sunoco Logistics and ETP’s retail marketing operations which were acquired on October 5, 2012. Operating expenses included in our consolidated results related to Sunoco Logistics and ETP’s retail marketing operations increased $90 million and $343 million, respectively, between

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periods. In addition, ETP’s interstate transportation and storage’s operating expenses increased $76 million primarily as a result of ETP’s consolidation of Southern Union. Operating expenses for ETP’s liquids transportation and services operations increased approximately $46 million primarily due to additional expenses from assets being placed in service. These increases were partially offset by decreases in ETP’s operating expenses due to its deconsolidation of certain operations during the periods, including ETP’s retail propane operations in January 2012 and SUGS in April 2013.
Selling, General and Administrative, Excluding Non-Cash Compensation Expense. For the year ended December 31, 2013 compared to the prior year, ETP’s selling, general and administrative expenses increased primarily as a result of a full year of operations related to Sunoco Logistics and ETP’s retail marketing operations which were acquired on October 5, 2012. Selling, general and administrative expenses included in our consolidated results related to Sunoco Logistics and ETP’s retail marketing operations increased $57 million and $57 million, respectively, between periods. These increases were partially offset by decreases in ETP’s interstate transportation and storage operations and midstream operations of $64 million and $42 million, respectively, primarily as a result of merger-related expenses recorded in 2012 and cost reduction initiatives in 2013.
Adjusted EBITDA Related to Discontinued Operations. In 2013, amounts reflect Southern Union’s distribution operations through the date of sale. Southern Union completed the sales of the assets of MGE in September 2013 and the assets of NEG in December 2013. In 2012, amounts reflect the operations of Canyon, which was sold in October 2012, and, for the period from March 26, 2012 to December 31, 2012, Southern Union’s distribution operations.
Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the years ended December 31, 2013 and 2012 consisted of the following:
 Years Ended December 31,  
 2013 2012 Change
AmeriGas$175
 $139
 $36
Citrus296
 228
 68
FEP75
 77
 (2)
Regency66
 —
 66
PES(30) 26
 (56)
Other47
 10
 37
Total Adjusted EBITDA related to unconsolidated affiliates$629
 $480
 $149
Amounts reflected above include a partial period for Citrus and AmeriGas in 2012 and a partial period for Regency in 2013.
Other. Other amounts in 2013 were primarily related to Sunoco, Inc.’s recognition of environmental obligations related to closed sites.
Investment in Regency
 Years Ended December 31,  
 2013 2012 Change
Revenues$2,521
 $2,000
 $521
Cost of products sold1,793
 1,387
 406
Gross margin728
 613
 115
Unrealized (gains) losses on commodity risk management activities9
 (5) 14
Operating expenses, excluding non-cash compensation expense(296) (228) (68)
Selling, general and administrative, excluding non-cash compensation expense(81) (95) 14
Adjusted EBITDA related to unconsolidated affiliates250
 222
 28
Other, net(2) 10
 (12)
Segment Adjusted EBITDA$608
 $517
 $91
Gross Margin. Regency’s gross margin increased for the year ended December 31, 2013 compared to the prior year primarily due to increased volumes in Regency’s South and West Texas gathering and processing operations.

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Operating Expenses, Excluding Non-Cash Compensation Expense. Regency’s operating expenses increased primarily due to the consolidation of SUGS beginning March 26, 2012 and increased pipeline and plant operating activity from organic growth.
Selling, General and Administrative, Excluding Non-Cash Compensation Expense. Regency’s selling, general and administrative expenses decreased due to the elimination of the amount allocated to SUGS assets by the previous parent and the decrease in management fees paid to ETE, partially offset by an increase in legal and consulting fees.
Adjusted EBITDA Related to Unconsolidated Affiliates. Regency’s adjusted EBITDA related to unconsolidated affiliates increased $30 million primarily due to the impact from Lone Star.
Other. Regency’s other decreased primarily as the result of recognition of a one-time producer payment received in March 2012 related to an assignment of certain contracts.
Investment in Lake Charles LNG
Lake Charles LNG provides terminal services for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long term contracts with a wholly-owned subsidiary of BG Group plc (“BG”).
Lake Charles LNG is currently developing a natural gas liquefaction facility with BG for the export of LNG. In December 2015, Lake Charles LNG received authorization from the FERC to site, construct, and operate facilities for the liquefaction and export of natural gas. On February 15, 2016, Royal Dutch Shell plc completed its acquisition of BG. Shell announced in the second quarter of 2016 that they will delay making a final investment decision (“FID”) for the Lake Charles LNG project and Shell has not advised LCL of any change in the status of the project. In the event that each of LCL and Shell elect to make an affirmative FID, construction of the project would be expected to commence promptly thereafter and first LNG exports would commence about four years later.

Asset Overview
Investment in ETP
The descriptions below include summaries of significant assets within ETP’s operations. Amounts, such as capacities, volumes and miles included in the descriptions below are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.
The following details the assets in ETP’s operations:
Intrastate Transportation and Storage
The following details pipelines and storage facilities in ETP’s intrastate transportation and storage operations:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline Pipeline Throughput Capacity
(Bcf/d)		 Working Storage Capacity
(Bcf/d)
ET Fuel System 100% 2,780
 5.2
 11.2
Oasis Pipeline 100% 750
 2.3
 —
HPL System 100% 3,920
 5.3
 52.5
East Texas Pipeline 100% 460
 2.4
 —
RIGS Haynesville Partnership Co. 49.99% 450
 2.1
 —
Comanche Trail Pipeline 16% 195
 1.1
 —
Trans-Pecos Pipeline 16% 143
 1.4
 —
The following information describes ETP’s principal intrastate transportation and storage assets:
The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipeline and related natural gas storage facilities. The ET Fuel System has many interconnections with pipelines providing direct access to power plants, other intrastate and interstate pipelines, and has bi-directional capabilities. It is strategically located near high-growth production areas and provides access to the Waha Hub near Midland, Texas, the Katy Hub near Houston, Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.
The ET Fuel System also includes the Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300 MMcf/d and an injection capacity of 75 MMcf/d, and the Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d. Storage capacity on the ET Fuel System is contracted to third parties under fee-based arrangements that extend through 2023.
In addition, the ET Fuel System is integrated with ETP’s Godley processing plant which gives ETP the ability to bypass the plant when processing margins are unfavorable by blending the untreated natural gas from the North Texas System with natural gas on the ET Fuel System while continuing to meet pipeline quality specifications.
The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis pipeline connects to the Waha and Katy market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis pipeline is integrated with ETP’s Southeast Texas System and is an important component to maximizing its Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing ETP to bypass its processing plants and treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The HPL System is an extensive network of intrastate natural gas pipelines, an underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in many of the major gas producing areas

in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing ETP to play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, as well as ETP’s Bammel storage facility.
The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a physical backup for on-system and off-system customers. As of December 31, 2017, ETP had approximately 10.8 Bcf committed under fee-based arrangements with third parties and approximately 36.9 Bcf stored in the facility for ETP’s own account.
The East Texas Pipeline connects three treating facilities, one of which ETP owns, with its Southeast Texas System. The East Texas pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The East Texas pipeline expansions include the 36-inch East Texas extension to connect ETP’s Reed compressor station in Freestone County to its Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting ETP’s Cleburne to Carthage pipeline to the HPL System.
RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets. The Partnership owns a 49.99% general partner interest in RIGS.
Comanche Trail is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail.
Trans-Pecos is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Midland, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.
Interstate Transportation and Storage
The following information describes ETP’s principal interstate transportation and storage assets:
Description of Assets Ownership Interest
(%)		 Miles of Natural Gas Pipeline 
Pipeline Throughput Capacity
(Bcf/d)
 
Working Gas Capacity
(Bcf/d)
Florida Gas Transmission Pipeline 50% 5,360
 3.1
 —
Transwestern Pipeline 100% 2,570
 2.1
 —
Panhandle Eastern Pipe Line 100% 5,980
 2.8
 83.9
Trunkline Gas Pipeline 100% 2,220
 0.9
 13.0
Tiger Pipeline 100% 195
 2.4
 —
Fayetteville Express Pipeline 50% 185
 2.0
 —
Sea Robin Pipeline 100% 830
 2.0
 —
Rover Pipeline 32.6% 713
 3.25
 —
Midcontinent Express Pipeline 50% 500
 1.8
 —
Gulf States 100% 10
 0.1
 —
The Florida Gas Transmission Pipeline (“FGT”) is an open-access interstate pipeline system with a mainline capacity of 3.1 Bcf/d and approximately 5,360 miles of pipelines extending from south Texas through the Gulf Coast region of the United States to south Florida. The FGT system receives natural gas from various onshore and offshore natural gas producing basins. FGT is the principal transporter of natural gas to the Florida energy market, delivering over 66% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains over 81 interconnects with major interstate and intrastate natural gas pipelines, which provide FGT’s customers access to diverse natural gas producing regions. FGT’s customers include electric utilities, independent power producers, industrials and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture between ETP and KMI.
The Transwestern Pipeline is an open-access interstate natural gas pipeline extending from the gas producing regions of West Texas, eastern and northwestern New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to pipeline interconnects at the California border. The Transwestern Pipeline has bi-directional capabilities and access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwestern New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandles. Natural

gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s Phoenix Lateral Pipeline, with a throughput capacity of 660 MMcf/d, connects the Phoenix area to the Transwestern mainline. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
The Panhandle Eastern Pipe Line’s transmission system consists of four large diameter pipelines with bi-directional capabilities, extending approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and into Michigan.
The Trunkline Gas Pipeline’s transmission system consists of one large diameter pipeline with bi-directional capabilities, extending approximately 1,400 miles from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan.
The Tiger Pipeline is an approximately 195-mile interstate natural gas pipeline with bi-directional capabilities, that connects to ETP’s dual 42-inch pipeline system near Carthage, Texas, extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana.
The Fayetteville Express Pipeline is an approximately 185-mile interstate natural gas pipeline that originates near Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.
The Sea Robin Pipeline’s transmission system consists of two offshore Louisiana natural gas supply systems extending approximately 120 miles into the Gulf of Mexico.
The Rover Pipeline is a new 713-mile natural gas pipeline designed to transport 3.25 Bcf/d of domestically produced natural gas from the Marcellus and Utica Shale production areas to markets across the United States as well as into the Union Gas Dawn Storage Hub in Ontario, Canada, for redistribution back into the United States or into the Canadian market.
The Midcontinent Express Pipeline is an approximately 500-mile interstate pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipeline System in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with KMI.
Gulf States owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
Midstream
The following details ETP’s assets in its midstream operations:
Description of Assets
Net Gas Processing Capacity
(MMcf/d)
 
Net Gas Treating Capacity
(MMcf/d)
South Texas Region:   
Southeast Texas System410
 510
Eagle Ford System1,920
 1,808
Ark-La-Tex Region1,025
 1,186
North Central Texas Region715
 212
Permian Region1,943
 1,580
Mid-Continent Region885
 20
Eastern Region—
 70
The following information describes ETP’s principal midstream assets:
South Texas Region:
The Southeast Texas System is an integrated system that gathers, compresses, treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and Eagle Ford shale formation. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. This system is connected to the Katy Hub through the East Texas Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plant (La Grange and Alamo) with aggregate capacity of 410 MMcf/d and natural gas treating facilities with aggregate capacity of 510 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process

the rich gas that flows through ETP’s gathering system to produce residue gas and NGLs. Residue gas is delivered into its intrastate pipelines and NGLs are delivered into ETP’s NGL pipelines to Lone Star.
ETP’s treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into ETP’s system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
The Eagle Ford Gathering System consists of 30-inch and 42-inch natural gas gathering pipelines with over 1.4 Bcf/d of capacity originating in Dimmitt County, Texas, and extending to both ETP’s King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. The Eagle Ford Gathering System includes four processing plants (Chisholm, Kenedy, Jackson and King Ranch) with aggregate capacity of 1,920 MMcf/d and multiple natural gas treating facilities with combined capacity of 1,808 MMcf/d. ETP’s Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to its intrastate transportation pipeline systems for deliveries of residue gas and are also connected with ETP’s NGL pipelines for delivery of NGLs to Lone Star.
Ark-La-Tex Region:
ETP’s Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including ETP’s Tiger Pipeline. ETP’s Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1,186 MMcf/d.
ETP’s PennTex Midstream System is primarily located in Lincoln Parish, Louisiana, and consists of the Lincoln Parish plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Arcadia, Louisiana, the Mt. Olive plant, a 200 MMcf/d design-capacity cryogenic natural gas processing plant located near Ruston, Louisiana, with on-site liquids handling facilities for inlet gas; a 35-mile rich gas gathering system that provides producers with access to ETP’s processing plants and third-party processing capacity; a 15-mile residue gas pipeline that provides market access for natural gas from ETP’s processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region; and a 40-mile NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from ETP’s processing plants.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in north and west Louisiana and several counties in East Texas. These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, and an interstate NGL pipeline. Collectively, the eight natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada and Brookeland) have an aggregate capacity of 1,025 MMcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, ETP offers producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas Region:
The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and transports natural gas from the Barnett and Woodford Shales. ETP’s North Central Texas assets include its Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 715 MMcf/d and aggregate treating capacity of 212 MMcf/d. The Godley plant is integrated with the ET Fuel System.
Permian Region:
The Permian Basin Gathering System offers wellhead-to-market services to producers in eleven counties in West Texas, as well as two counties in New Mexico which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of ETP’s system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that ETP gathers and processes, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. The NGL market outlets includes Lone Star’s liquids pipelines. The Permian Basin Gathering System includes ten processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther and Rebel) with an aggregate processing capacity of 1,618 MMcf/d, treating capacity of 1,580 MMcf/d, and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.
ETP owns a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. ETP operates the plant and related facilities on behalf of Mi Vida JV.

ETP owns a 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGL-rich Bone Spring and Avalon Shale formations in West Texas. The joint venture owns a 25 MMcf/d refrigeration plant and a 125 MMcf/d cryogenic processing plant.
Mid-Continent Region:
The Mid-Continent Systems are located in two large natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas, and the Anadarko Basin in western Oklahoma and the Texas Panhandle. These mature basins have continued to provide generally long-lived, predictable production volume. ETP’s Mid-Continent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Mid-Continent Systems include fourteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray and Gray) with an aggregate capacity of 885 MMcf/d and one natural gas treating facility with aggregate capacity of 20 MMcf/d.
ETP operates its Mid-Continent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
ETP also owns the Hugoton Gathering System that has 1,900 miles of pipeline extending over nine counties in Kansas and Oklahoma. This system is operated by a third party.
Eastern Region:
The Eastern Region assets are located in nine counties in Pennsylvania, three counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. ETP’s Eastern Region assets include approximately 500 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems. The fresh water pipeline system and Ohio gathering assets are held by jointly-owned entities.
ETP also owns a 51% membership interest in Aqua – PVR, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
ETP and Traverse ORS LLC, a subsidiary of Traverse Midstream Partners LLC, own a 75% and 25% membership interest, respectively, in the ORS joint venture. On behalf of ORS, ETP operates ORS’s Ohio Utica River System (the “ORS System”), which consists of 47 miles of 36-inch and 13 miles of 30-inch gathering trunklines that delivers up to 2.1 Bcf/d to Rockies Express Pipeline (“REX”), Texas Eastern Transmission, and others.

NGL and Refined Products Transportation and Services
The following details the assets in ETP’s NGL and refined products transportation and services operations:
Description of Assets
Miles of Liquids Pipeline (2)
 
Pipeline Throughput Capacity
(MBbls/d)
 
NGL Fractionation / Processing Capacity
(MBbls/d)
 
Working Storage Capacity
(MBbls)
Liquids Pipelines:       
Lone Star Express535
 507
 —
 —
West Texas Gateway Pipeline512
 240
 —
 —
Lone Star1,617
 120
 —
 —
Mariner East300
 70
    
Mariner South67
 200
    
Mariner West395
 50
    
Other NGL Pipelines645
 591
 —
 —
Liquids Fractionation and Services Facilities:       
Mont Belvieu Facilities163
 42
 520
 50,000
Sea Robin Processing Plant1
—
 —
 26
 —
Refinery Services1
103
 —
 25
 —
Hattiesburg Storage Facilities—
 —
 —
 3,000
NGLs Terminals:       
Nederland—
 —
 —
 1,000
Marcus Hook Industrial Complex—
 —
 90
 5,000
Inkster—
 —
 —
 1,000
Refined Products Pipelines2,200
 800
 —
 —
Refined Products Terminals:       
Eagle Point—
 —
 —
 6,000
Marcus Hook Industrial Complex—
 —
 —
 1,000
Marcus Hook Tank Farm—
 —
 —
 2,000
Marketing Terminals—
 —
 —
 8,000
(1)
Additionally, the Sea Robin Processing Plant and Refinery Services have residue capacities of 850 MMcf/d and 54 MMcf/d, respectively.
(2)
Miles of pipeline as reported to PHMSA.
The following information describes ETP’s principal NGL and refined products transportation and services assets:
The Lone Star Express System is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipeline that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility.
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas.
The Mariner East pipeline transports NGLs from the Marcellus and Utica Shales areas in Western Pennsylvania, West Virginia and Eastern Ohio to destinations in Pennsylvania, including ETP’s Marcus Hook Industrial Complex on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets. The first phase of the project, referred to as Mariner East 1, consisted of interstate and intrastate propane and ethane service and commenced operations in the fourth quarter of 2014 and the first quarter of 2016, respectively. The second phase of the project, referred to as Mariner East 2, will expand the total takeaway capacity to 345 MBbls/d for interstate and intrastate propane, ethane and butane service, and is expected to commence operations in the second quarter of 2018.

The Mariner South pipeline is part of a joint project with Lone Star to deliver export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to ETP’s marine terminal in Nederland, Texas.
The Mariner West pipeline provides transportation of ethane from the Marcellus shale processing and fractionating areas in Houston, Pennsylvania to Marysville, Michigan and the Canadian border. Mariner West commenced operations in the fourth quarter of 2013, with capacity to transport approximately 50 MBbls/d.
Refined products pipelines include approximately 2,200 miles of refined products pipelines in several regions of the United States. The pipelines primarily provide transportation in the northeast, midwest, and southwest United States markets. These operations include ETP’s controlling financial interest in Inland Corporation (“Inland”). The mix of products delivered varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. In addition, weather conditions in the areas served by the refined products pipelines affect both the demand for, and the mix of, the refined products delivered through the pipelines, although historically, any overall impact on the total volume shipped has been short-term. The products transported in these pipelines include multiple grades of gasoline, and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC and other state regulatory agencies, as applicable.
Other NGL pipelines include the 127-mile Justice pipeline with capacity of 375 MBbls/d, the 45-mile Freedom pipeline with a capacity of 56 MBbls/d, the 20-mile Spirit pipeline with a capacity of 20 MBbls/d and a 50% interest in the 87-mile Liberty pipeline with a capacity of 140 MBbls/d.
ETP’s Mont Belvieu storage facility is an integrated liquids storage facility with over 50 million Bbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined product pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
ETP’s Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator V is currently under construction and is scheduled to be operational by the third quarter of 2018.
Sea Robin is a rich gas processing plant located on the Sea Robin Pipeline in southern Louisiana. The plant is connected to nine interstate and four intrastate residue pipelines, as well as various deep-water production fields.
Refinery Services consists of a refinery off-gas processing unit and an O-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting complex located along the Mississippi River refinery corridor in southern Louisiana.  The off-gas processing unit cryogenically processes refinery off-gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components.  The O-grade fractionator and RGP splitting complex, located in Geismar, Louisiana, is connected by approximately 103 miles of pipeline to the Chalmette processing plant, which has a processing capacity of 54 MMcf/d.
The Hattiesburg storage facility is an integrated liquids storage facility with approximately 3 million Bbls of salt dome capacity, providing 100% fee-based cash flows.
The Nederland terminal, in addition to crude oil activities, also provides approximately 1 million Bbls of storage and distribution services for NGLs in connection with the Mariner South pipeline, which provides transportation of propane and butane products from the Mont Belvieu region to the Nederland terminal, where such products can be exported via ship.
The Marcus Hook Industrial Complex includes fractionation, terminalling and storage assets, with a capacity of approximately 2 million Bbls of NGL storage capacity in underground caverns, 3 million Bbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 million Bbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGLs storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for the Mariner East 1 pipeline, and will provide similar off-take capabilities for the Mariner East 2 pipeline when it commences operations.
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 1 million Bbls of NGLs. ETP uses the Inkster terminal's storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers and a refinery in Western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
ETP has approximately 40 refined products terminals with an aggregate storage capacity of approximately 8 million Bbls that facilitate the movement of refined products to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.

In addition to crude oil service, the Eagle Point terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and barges. The tank farm has a total active refined products storage capacity of approximately 6 million Bbls, and provides customers with access to the facility via ship, barge and pipeline. The terminal can deliver via ship, barge, truck or pipeline, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
The Marcus Hook Tank Farm has a total refined products storage capacity of approximately 2 million Bbls of refined products storage. The tank farm historically served Sunoco Inc.’s Marcus Hook refinery and generated revenue from the related throughput and storage. In 2012, the main processing units at the refinery were idled in connection with Sunoco Inc.’s exit from its refining business. The terminal continues to receive and deliver refined products via pipeline and now primarily provides terminalling services to support movements on ETP’s refined products pipelines.
The Eastern refined products pipelines consists of approximately 470 miles of 6-inch to 24-inch diameters refined product pipelines in Eastern, Central and North Central Pennsylvania, approximately 162 miles of 8-inch refined products pipeline in western New York and approximately 182 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
The Mid-Continent refined products pipelines primarily consists of approximately 212 miles of 3-inch to 12-inch refined products pipelines in Ohio, approximately 85 miles of 6-inch to 12-inch refined products pipeline in Western Pennsylvania and approximately 52 miles of 8-inch refined products pipeline in Michigan.
The Southwest refined products pipelines is located in Eastern Texas and consists primarily of approximately 300 miles of 8-inch diameter refined products pipeline.
The Inland refined products pipeline, approximately 350 miles of pipeline in Ohio, consists of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 205 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 53 miles of 8-inch diameter refined products pipeline in western Ohio and the remaining refined products pipeline primarily consists of 5-inch diameter pipeline in Northeast Ohio.
Crude Oil Transportation and Services
The following details ETP’s pipelines and terminals in its crude oil transportation and services operations:
Description of Assets
Miles of Crude Pipeline (1)
Working Storage Capacity
(MBbls)
Dakota Access Pipeline1,172
—
Energy Transfer Crude Oil Pipeline743
—
Bayou Bridge Pipeline49
—
Permian Express Pipelines1,712
—
Other Crude Oil Pipelines5,682
—
Nederland Terminal—
26,000
Fort Mifflin Terminal—
570
Eagle Point Terminal—
1,000
Midland Terminal—
2,000
Marcus Hook Industrial Complex—
1,000
Patoka, Illinois Terminal—
2,000
(1)
Miles of pipeline as reported to PHMSA.
ETP’s crude oil operations consist of an integrated set of pipeline, terminalling, and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details ETP’s assets in its crude oil transportation and services operations:
Crude Oil Pipelines
ETP’s crude oil pipelines consist of approximately 9,358 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States, including ETP’s wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC (“PET”), and Mid-Valley Pipeline Company (“Mid-Valley”). Additionally, ETP has equity ownership interests in two crude oil pipelines.

ETP’s crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. ETP’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.
Bakken Pipeline. Dakota Access and ETCO are collectively referred to as the “Bakken Pipeline.” The Bakken Pipeline is a 1,915 mile pipeline with an initial capacity of 470 MBbls/d, expandable to 570 MBbls/d, that transports domestically produced crude oil from the Bakken/Three Forks production areas in North Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including ETP’s crude terminal in Nederland Texas.
The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the Midwest and Gulf Coast regions.
Dakota Access went into service on June 1, 2017 and consists of approximately 1,172 miles of 30-inch diameter pipeline traversing North Dakota, South Dakota, Iowa and Illinois. Crude oil transported on the Dakota Access originates at six terminal locations in the North Dakota counties of Mountrail, Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the ETCO Pipeline for delivery to the Gulf Coast, or can be transported via other pipelines to refining markets throughout the Midwest.
ETCO went into service on June 1, 2017 and consists of more than 743 miles consisting of 678 miles of mostly 30-inch converted natural gas pipeline and 65 miles of new 30-inch pipeline from Patoka, Illinois to Nederland, Texas, where the crude oil can be refined or further transported to additional refining markets.
Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between ETP and Phillips 66, in which ETP has a 60% ownership interest and serves as the operator of the pipeline. Phase I of the pipeline, which consists of a 30-inch pipeline from Nederland, Texas to Lake Charles, Louisiana, went into service in April 2016. Phase II of the pipeline, which will consist of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, is expected to be completed in the second half of 2018.
When completed the Bayou Bridge Pipeline will have a capacity expandable to approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries located in the Gulf Coast region.
Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Pegasus pipelines contributed to this joint venture by ExxonMobil. These pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the Permian Basin, which origins in multiple locations in Western Texas.
Other Crude Oil pipelines include the Mid-Valley pipeline system which originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United States.
In addition, we own a crude oil pipeline that runs from Marysville, Michigan to Toledo, Ohio, and a truck injection point for local production at Marysville. This pipeline receives crude oil from the Enbridge pipeline system for delivery to refineries located in Toledo, Ohio and to MPLX’s Samaria, Michigan tank farm, which supplies its Marathon Petroleum Corporation’s refinery in Detroit, Michigan.
We also own and operate crude oil pipeline and gathering systems in Oklahoma. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma system to Cushing. We are one of the largest purchasers of crude oil from producers in the state, and our crude oil acquisition and marketing activities business is the primary shipper on our Oklahoma crude oil system.
Crude Oil Terminals
Nederland. The Nederland terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores, and distributes crude oil, NGLs, feedstocks, lubricants, petrochemicals, and bunker oils (used for fueling ships and other marine vessels), and also blends lubricants. The terminal currently has a total storage capacity of approximately 26 million Bbls in approximately 150 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland terminal can receive crude oil at four of its five ship docks and four barge berths. The four ship docks are capable of receiving over 2 million Bbls/d of crude oil. In addition to ETP’s crude oil pipelines, the terminal can also receive crude oil through a number of other pipelines, including the DOE. The DOE pipelines connect the terminal to the United

States Strategic Petroleum Reserve’s West Hackberry caverns at Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 million Bbls.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has two ship docks and three barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 million Bbls/d of crude oil to ETP’s crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland terminal generates crude oil revenues primarily by providing term or spot storage services and throughput capabilities to a number of customers.
Fort Mifflin. The Fort Mifflin terminal complex is located on the Delaware River in Philadelphia, Pennsylvania and includes the Fort Mifflin terminal, the Hog Island wharf, the Darby Creek tank farm and connecting pipelines. Revenues are generated from the Fort Mifflin terminal complex by charging fees based on throughput.
The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 570 MBbls. Crude oil and some refined products enter the Fort Mifflin terminal primarily from marine vessels on the Delaware River. One Fort Mifflin dock is designed to handle crude oil from very large crude carrier-class tankers and smaller crude oil vessels. The other dock can accommodate only smaller crude oil vessels.
The Hog Island wharf is located next to the Fort Mifflin terminal on the Delaware River and receives crude oil via two ship docks, one of which can accommodate crude oil tankers and smaller crude oil vessels, and the other of which can accommodate some smaller crude oil vessels.
The Darby Creek tank farm is a primary crude oil storage terminal for the Philadelphia refinery, which is operated by PES under a joint venture with Sunoco, Inc. This facility has a total storage capacity of approximately 3 million Bbls. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via ETP’s pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via ETP’s pipelines.
Eagle Point. The Eagle Point terminal is located in Westville, New Jersey and consists of docks, truck loading facilities and a tank farm. The docks are located on the Delaware River and can accommodate three marine vessels (ships or barges) to receive and deliver crude oil, intermediate products and refined products to outbound ships and barges. The tank farm has a total active storage capacity of approximately 1 million Bbls and can receive crude oil via barge and rail and deliver via ship and barge, providing customers with access to various markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
Midland. The Midland terminal is located in Midland, Texas and was acquired in November 2016 from Vitol. The facility includes approximately 2 million Bbls of crude oil storage, a combined 14 lanes of truck loading and unloading, and provides access to the Permian Express 2 transportation system.
Marcus Hook Industrial Complex. The Marcus Hook Industrial Complex can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has a total active crude oil storage capacity of approximately 1 million Bbls.
Patoka, Illinois Terminal. The Patoka, Illinois terminal is a tank farm and was contributed by ExxonMobil to the PEP joint venture and is located in Marion County, Illinois. The facility includes 234 acres of owned land and provides for approximately 2 million Bbls of crude oil storage.
Crude Oil Acquisition and Marketing
ETP’s crude oil acquisition and marketing operations are conducted using ETP’s assets, which include approximately 370 crude oil transport trucks and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets.
All Other
Equity Method Investments
Sunoco LP. ETP has an equity method investment in limited partnership units of Sunoco LP. As of December 31, 2017, ETP’s investment consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, ETP’s investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units.

PES. ETP has a non-controlling interest in PES, comprising 33% of PES’ outstanding common units. As discussed in “ETP’s Other Operations and Investments” above, PES Holdings and eight affiliates filed for Chapter 11 bankruptcy protection on January 21, 2018.
Contract Services Operations
ETP owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. ETP’s contract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
ETP owns all of the outstanding equity interests of CDM, which operates a natural gas compression equipment business with operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas. As discussed in “Strategic Transactions,” in January 2018, ETP entered into an agreement to contribute CDM to USAC.
ETP owns 100% of the membership interests of ETG, which owns all of the partnership interests of ETT. ETT provides compression services to customers engaged in the transportation of natural gas, including ETP’s other operations.
Natural Resources Operations
ETP’s Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. ETP also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2017, ETP owned or controlled approximately 766 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the operator of end-user coal handling facilities.
Liquefaction Project
LCL, an entity whose parent is owned 60% by ETE and 40% by ETP, is in the process of developing a liquefaction project at the site of ETE’s existing regasification facility in Lake Charles, Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc (now "Shell") related to this project expired in February 2017. On June 28, 2017, LCL signed a memorandum of understanding with Korea Gas Corporation and Shell to study the feasibility of a joint development of the Lake Charles liquefaction project. The project would utilize existing dock and storage facilities owned by ETE located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia).  Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.
The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of exporting and importing LNG. Shell is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project would be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL. In March 2013, LCL obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”). In July 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”). The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively.

ETP has received its wetlands permits from the United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.
Investment in Sunoco LP
The following details the assets of Sunoco LP:
Wholesale Subsidiaries
Sunoco LLC, a Delaware limited liability company, primarily distributes motor fuel across 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LLC also processes transmix and distributes refined product through its terminals in Alabama and the Greater Dallas, Texas metroplex.
Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands.
Retail Subsidiaries
Susser Petroleum Property Company LLC, a Delaware limited liability company, primarily owns and leases convenience store properties.
Susser, a Delaware corporation, sells motor fuel and merchandise in Texas, New Mexico, and Oklahoma through Stripes-branded convenience stores.
Sunoco Retail, a Pennsylvania limited liability company, owns and operates convenience stores that sell motor fuel and merchandise primarily in Pennsylvania, New York, and Florida.
MACS Retail LLC, a Virginia limited liability company, owns and operates convenience stores in Virginia, Maryland, and Tennessee.
Aloha Petroleum, Ltd., a Hawaii corporation, owns and operates convenience stores on the Hawaiian Islands.
As of December 31, 2017, prior to the closing of the amended and restated purchasing agreement with 7-Eleven, Sunoco LP’s retail segment operated approximately 1,348 convenience stores and retail fuel outlets. Sunoco LP’s retail convenience stores operates under several brands, including its proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. Sunoco LP has company operated sites in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.
As of December 31, 2017, Sunoco LP operated approximately 746 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on local customer demand and preferences. Sunoco LP built approximately 265 large-format convenience stores from January 2000 through December 31, 2017. Sunoco LP has implemented its proprietary, in-house Laredo Taco Company restaurant concept in approximately 477 Stripes convenience stores. Sunoco LP also owns and operates ATM and proprietary money order systems in most Stripes stores and provides other services such as lottery, prepaid telephone cards, wireless services and car washes.
As of December 31, 2017, Sunoco LP operated approximately 441 retail convenience stores and fuel outlets, primarily under its proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 404 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.
As of December 31, 2017, Sunoco LP operated approximately 161 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2017, MACS operated approximately 107 retail convenience stores and Aloha operated approximately 54 Aloha, Shell, and Mahalo branded fuel stations.
Investment in Lake Charles LNG
Regasification Facility
Lake Charles LNG, a wholly-owned subsidiary of ETE, owns a LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/day.

Liquefaction Project
LCL, an entity owned 60% by ETE and 40% by ETP, is in the process of developing the liquefaction project in conjunction with BG pursuant to a project development agreement entered into in September 2013 and scheduled to expire at the end of February 2017, subject to the parties’ right to mutually extend the term. Pursuant to this agreement, each of LCL and BG are obligated to pay 50% of the development expenses for the liquefaction project, subject to reimbursement by the other party if such party withdraws from the project prior to both parties making an affirmative FID to become irrevocably obligated to fully develop the project, subject to certain exceptions. The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility will become a bi-directional facility capable of exporting and importing LNG. BG is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project is expected to be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.
The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of exporting and importing LNG. Shell is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project would be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.
The export of LNG produced by the liquefaction project from the United States would be undertaken under long-term export authorizations issued by the DOE to LCL. In March 2013, LCL obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”).  In July 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”).  The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively. 
In addition, We have received our wetlands permits from the United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.
Competition
Natural Gas
The business of providing natural gas gathering, compression, treating, transporting, storing and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage operations are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.
We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours.
In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

NGL
In markets served by our NGL pipelines, we face competition with other pipeline companies, including those affiliated with major oil, petrochemical and natural gas companies, and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service. We face competition with other storage facilities based on fees charged and the ability to receive and distribute the customer’s products. We compete with a number of NGL fractionators in Texas and Louisiana. Competition for such services is primarily based on the fractionation fee charged.
Crude Oil and Products
In markets served by our products and crude oil pipelines, we face competition from other pipelines as well as rail and truck transportation. Generally, pipelines are the lowest cost method for long-haul, overland movement of products and crude oil. Therefore, the most significant competitors for large volume shipments in the areas served by our pipelines are other pipelines. In addition, pipeline operations face competition from rail and trucks that deliver products in a number of areas that our pipeline operations serve. While their costs may not be competitive for longer hauls or large volume shipments, rail and trucks compete effectively for incremental and marginal volume in many areas served by our pipelines.
With respect to competition from other pipelines, the primary competitive factors consist of transportation charges, access to crude oil supply and market demand. Competitive factors in crude oil purchasing and marketing include price and contract flexibility, quantity and quality of services, and accessibility to end markets.
Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.
Wholesale Fuel Distribution and Retail Marketing
In our wholesale fuel distribution business, we compete primarily with other independent motor fuel distributors. The markets for distribution of wholesale motor fuel and the large and growing convenience store industry are highly competitive and fragmented, which results in narrow margins. We have numerous competitors, some of which may have significantly greater resources and name recognition than we do. Significant competitive factors include the availability of major brands, customer service, price, range of services offered and quality of service, among others. We rely on our ability to provide value-added and reliable service and to control our operating costs in order to maintain our margins and competitive position.
In our retail business, we face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, supermarkets, drugstores, dollar stores, club stores and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending on the geographical area. It also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of operation, store safety, customer loyalty and brand recognition. We compete by pricing gasoline competitively, combining our retail gasoline business with convenience stores that provide a wide variety of products, and using advertising and promotional campaigns.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies, and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory

changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
Natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. The discovery and development of new shale formations across the United States has created an abundance of natural gas and crude oil resulting in a negative impact on prices in recent years for natural gas and crude oil. As a result, some of our exploration and production customers have been adversely impacted; however, we are monitoring these customers and mitigating credit risk as necessary.
During the year ended December 31, 2017, none of our customers individually accounted for more than 10% of our consolidated revenues.
Regulation of Interstate Natural Gas Pipelines.The FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines. Under the Natural Gas Act (“NGA”), the FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes, “transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. The Florida Gas Transmission, Transwestern, Panhandle Eastern, Trunkline Gas, Tiger, Fayetteville Express, Sea Robin, Gulf States and Midcontinent Express pipelines transport natural gas in interstate commerce and thus each qualifies as a “natural-gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We also hold certain natural gas storage facilities that are subject to the FERC’s regulatory oversight under the NGA.
The FERC’s NGA authority includes the power to:
approve the siting, construction and operation of new facilities;
review and approve transportation rates;
determine the types of services our regulated assets are permitted to perform;
regulate the terms and conditions associated with these services;
permit the extension or abandonment of services and facilities;
require the maintenance of accounts and records; and
authorize the acquisition and disposition of facilities.
Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are required to be on file with the FERC. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition warrants such discounts. Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among other requirements, such companies’ tariffs offer a cost-based recourse rate available to a prospective shipper as an alternative to the negotiated rate. Natural gas companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. Existing tariff rates may be challenged by complaint or on FERC’s own motion, and if found unjust and unreasonable, may be altered on a prospective basis from no earlier than the date of the complaint or initiation of a proceeding by the FERC. The FERC must also approve all rate changes. We cannot guarantee that the FERC will allow us to charge rates that fully recover our costs or continue to pursue its approach of pro-competitive policies.

For two of our NGA-jurisdictional natural gas companies, Tiger and Fayetteville Express, the large majority of capacity in those pipelines is subscribed for lengthy terms under FERC-approved negotiated rates.  However, as indicated above, cost-based recourse rates are also offered under their respective tariffs.
Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of electric energy or natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction: (i) to defraud using any device, scheme or artifice; (ii) to make any untrue statement of material fact or omit a material fact; or (iii) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). With regard to our physical purchases and sales of natural gas, NGLs or other energy commodities; our gathering or transportation of these energy commodities; and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability

to assess or seek civil penalties of up to approximately $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Failure to comply with the NGA, the Energy Policy Act of 2005, the CEA and the other federal laws and regulations governing our operations and business activities can result in the imposition of administrative, civil and criminal remedies.
Regulation of Intrastate Natural Gas and NGL Pipelines.  Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates and terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”). The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The rates and terms and conditions of some transportation and storage services provided on the Oasis pipeline, HPL System, East Texas pipeline, ET Fuel System, Trans-Pecos and Comanche Trail are subject to FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the TRRC. Our intrastate pipeline and storage operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.
Our NGL pipelines and operations may also be or become subject to state public utility or related jurisdiction which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities. In addition, the rates, terms and conditions for shipments of NGLs on our pipelines are subject to regulation by FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all NGLs shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of Sales of Natural Gas and NGLs.The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation.
To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to the use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s tariff, could result in the imposition of civil and criminal penalties.
Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those operations of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas marketers with whom we compete.
Regulation of Gathering Pipelines.  Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines in Texas, Louisiana and West Virginia that we believe meet the traditional tests the FERC uses to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject

of substantial litigation and varying interpretations, so the classification and regulation of our gathering facilities could be subject to change based on future determinations by the FERC, the courts and Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.
Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.
We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Regulation of Interstate Crude Oil, NGL and Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by the FERC under the ICA, the EPAct of 1992, and related rules and orders. The ICA requires that tariff rates for petroleum pipelines be “just and reasonable” and not unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. This statute also permits interested persons to challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a substantial economic interest in the tariff rate level. Although no assurance can be given that the tariff rates charged by us ultimately will be upheld if challenged, management believes that the tariff rates now in effect for our pipelines are within the maximum rates allowed under current FERC policies and precedents.
For many locations served by our product and crude pipelines, we are able to establish negotiated rates.  Otherwise, we are permitted to charge cost-based rates, or in many cases, grandfathered rates based on historical charges or settlements with our customers. To the extent we rely on cost-of-service ratemaking to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise. In 2005, FERC issued a policy statement stating that it would permit common carriers, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. Whether a pipeline’s owners have such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for common carriers that are organized as pass-through entities, it still entails rate risk due to the FERC’s case-by-case review approach. The application of this policy, as well as any decision by

FERC regarding our cost of service, may also be subject to review in the courts. In December 2016, FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs. FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect to the notice of inquiry ended on April 7, 2017. The outcome of the inquiry is still pending.
Finally, in November 2017 FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline.  In particular, FERC’s November 2017 order prohibits  buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service  is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss.  Several parties have requested that FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order.  We are unable to predict how FERC will respond to such requests.  Depending on how FERC responds, it could have an impact on the rates we are permitted to charge.
EPAct 1992 required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPIFG. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2011 and ending June 30, 2016, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPIFG plus 2.65%. Beginning July 1, 2016, the indexing method provided for annual changes equal to the change in PPIFG plus 1.23%. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior 2 years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules ended on March 17, 2017. FERC has taken no further action on the proposed rule to date.
Finally, in November 2017 FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s interstate pipeline.  In particular, FERC’s November 2017 order prohibits  buy/sell arrangements by a marketing affiliate if: (i) the transportation differential applicable to its affiliate’s interstate pipeline transportation service  is at a discount to the affiliated pipeline’s filed rate for that service; and (ii) the pipeline affiliate subsidizes the loss.  Several parties have requested that FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order.  We are unable to predict how FERC will respond to such requests.  Depending on how FERC responds, it could have an impact on the rates we are permitted to charge.
Regulation of Intrastate Crude Oil, NGL and Products Pipelines. Some of our crude oil, NGL and products pipelines are subject to regulation by the TRRC, the PA PUC, and the Oklahoma Corporation Commission. The operations of our joint venture interests are also subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.
In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of Pipeline Safety.Our pipeline operations are subject to regulation by the DOT, through the PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA,

as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Failure to comply with the pipeline safety laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays in permitting or the performance of projects, or the issuance of injunctions limiting or prohibiting some or all of our operations in the affected area.
The HLPSA and NGPSA have been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”). The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum penalty caps do not apply to certain civil enforcement actions. Effective April 27, 2017, to account for inflation, those maximum civil penalties were increased to $209,002 per day, with a maximum of $2,090,022 for a series of violations. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.
In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which we conduct operations typically have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines. Under such state regulatory programs, states have the authority to conduct pipeline inspections, to investigate accidents and to oversee compliance and enforcement, safety programs and record maintenance and reporting. Congress, PHMSA and individual states may pass or implement additional safety requirements that could result in increased compliance costs for us and other companies in our industry. For example, federal construction, maintenance and inspection standards under the NGPSA that apply to pipelines in relatively populated areas may not apply to gathering lines running through rural regions. This “rural gathering exemption” under the NGPSA presently exempts substantial portions of our gathering facilities located outside of cities, towns or any area designated as residential or commercial from jurisdiction under the NGPSA, but does not apply to our intrastate natural gas pipelines. In recent years, the PHMSA has considered changes to this rural gathering exemption, including publishing an advance notice of proposed rulemaking relating to gas pipelines in 2011, in which the agency sought public comment on possible changes to the definition of “high consequence areas” and “gathering lines” and the strengthening of pipeline integrity management requirements. In April 2016, pursuant to one of the requirements of the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that, among other things, would expand certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; require natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and require certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has not yet finalized the March 2016 proposed rulemaking.
In January 2017, PHMSA issued a final rule amending federal safety standards for hazardous liquid pipelines. The final rule is the latest step in a lengthy rulemaking process that began in 2010 with a request for comments and continued with publication of a rulemaking proposal in October 2015. The general effective date of this final rule is six months from publication in the Federal Register, but it is currently subject to further administrative review in connection with the transition of Presidential administrations and thus, implementation of this final rule remains uncertain. The final rule addresses several areas including reporting requirements for gravity and unregulated gathering lines, inspections after weather or climatic events, leak detection system requirements, revisions to repair criteria and other integrity management revisions. In addition, PHMSA issued regulations on January 23, 2017, on operator qualification, cost recovery, accident and incident notification and other pipeline safety changes that are now effective. These regulations are also subject, however, to potential further review in connection with the transition of Presidential

administrations. Historically, our pipeline safety costs have not had a material adverse effect on our business or results of operations but there is no assurance that such costs will not be material in the future, whether due to elimination of the rural gathering exemption or otherwise due to changes in pipeline safety laws and regulations.
In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the federal OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators, including the Texas Railroad Commission, have in recent years, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. To the extent that these actions are pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.
Environmental Matters
General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering, processing, storage and transmission of natural gas and the storage and transportation of NGLs, crude oil and refined products is subject to stringent federal, tribal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and criminal sanctions, third-party claims for personal injury or property damage, capital expenditures to retrofit or upgrade our facilities and programs, or curtailment or cancellation of permits on operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of planning, permitting, constructing and operating our plants, pipelines and other facilities. As a result of these laws and regulations, our construction and operation costs include capital, operating and maintenance cost items necessary to maintain or upgrade our equipment and facilities.
We have implemented procedures designed to ensure that governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. Historically, our environmental compliance costs have not had a material adverse effect on our business, results of operations or financial condition; however, there can be no assurance that such costs will not be material in the future. For example, we cannot be certain, however, that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent environmental laws and regulations or unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.
Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to strict, joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition or that may be subject to other waste disposal laws and regulations. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed.
We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, as amended, (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial

portion of the RCRA hazardous waste requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent non-hazardous management standards. From time to time, the EPA has considered or third parties have petitioned the agency on the adoption of stricter handling, storage and disposal standards for nonhazardous wastes, including certain wastes associated with the exploration, development and production of crude oil and natural gas. For example, following the filing of a lawsuit by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the United States District Court for the District of Columbia on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense and, in the case of our oil and natural gas exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in demand for our processing, transportation and storage services.
We currently own or lease sites that have been used over the years by prior owners and lessees and by us for various activities related to gathering, processing, storage and transmission of natural gas, NGLs, crude oil and products. Waste disposal practices within the oil and gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on or under various sites during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.
As of December 31, 2017 and 2016, accruals of $372 million and $344 million, respectively, were recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover estimated material environmental liabilities including, for example, certain matters assumed in connection with our acquisition of the HPL System, our acquisition of Transwestern, potential environmental liabilities for three sites that were formerly owned by Titan Energy Partners, L.P. or its predecessors, and the predecessor owner’s share of certain environmental liabilities of ETC OLP.
The Partnership is subject to extensive and frequently changing federal, tribal, state and local laws and regulations, including those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and composition of fuels. These laws and regulations require environmental assessment and remediation efforts at many of Sunoco, Inc.’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $284 million and $289 million at December 31, 2017 and 2016, respectively, which is included in the total accruals above. These legacy sites that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that are no longer operated by Sunoco, Inc., closed and/or sold refineries and other formerly owned sites. In December 2013, a wholly-owned captive insurance company was established for these legacy sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. As of December 31, 2017 the captive insurance company held $207 million of cash and investments.
The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Under various environmental laws, including the RCRA, the Partnership has initiated corrective remedial action at certain of its facilities, formerly owned facilities and at certain third-party sites. At the Partnership’s major manufacturing facilities, we have typically assumed continued industrial use and a containment/remediation strategy focused on eliminating unacceptable risks to human health or the environment. The remediation accruals for these sites reflect that strategy. Accruals include amounts designed to prevent or mitigate off-site migration and to contain the impact on the facility property, as well as to address known, discrete

areas requiring remediation within the plants. Remedial activities include, for example, closure of RCRA waste management units, recovery of hydrocarbons, handling of impacted soil, mitigation of surface water impacts and prevention or mitigation of off-site migration. A change in this approach as a result of changing the intended use of a property or a sale to a third party could result in a comparatively higher cost remediation strategy in the future.
In general, a remediation site or issue is typically evaluated on an individual basis based upon information available for the site or issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (for example, service station sites) in determining the amount of probable loss accrual to be recorded. The estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance allows us the minimum amount of the range to accrue. Accordingly, the low end of the range often represents the amount of loss which has been recorded.
In addition to the probable and estimable losses which have been recorded, management believes it is reasonably possible (that is, it is less than probable but greater than remote) that additional environmental remediation losses will be incurred. At December 31, 2017, the aggregate of such additional estimated maximum reasonably possible losses, which relate to numerous individual sites, totaled approximately $5 million, which amount is in excess of the $372 million in environmental accruals recorded on December 31, 2017. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics and retail assets, and in many cases, reflects the upper end of the loss ranges which are described above. Such estimates include potentially higher contractor costs for expected remediation activities, the potential need to use more costly or comprehensive remediation methods and longer operating and monitoring periods, among other things.
In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years, but management can provide no assurance that it would be over many years. If changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time.  As a result, from time to time, significant charges against income for environmental remediation may occur. And while management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position, it can provide no assurance.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $5 million, which is included in the total environmental accruals mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. Such future costs are not expected to have a material impact on our financial position, results of operations or cash flows, but management can provide no assurance.
Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We will incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. Historically, our costs for compliance with existing Clean Air Act and comparable state law requirements have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future. The EPA and state agencies are often considering, proposing or finalizing new regulations that could impact our existing operations and the costs and timing of new infrastructure development. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering

the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to our customers’ operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.
Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended, (“Clean Water Act”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the United States. Pursuant to the Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In May 2015, the EPA issued a final rule that attempts to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the United States Sixth Circuit Court of Appeals as that appellate court and numerous district courts ponder lawsuits opposing implementation of the rule. In June 2015, the EPA and the United States Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the United States Supreme Court agreed to hear the case. The EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested May 2015 rule would not take effect until two years after the November 2017 proposed rule was finalized and published in the Federal Register. Recently, on January 22, 2018, the United States Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, while implementation of the 2015 rule currently remains stayed, the previously-filed district court cases will be allowed to proceed. On January 31, 2018, the EPA and Corps finalized a rule that would delay applicability of the rule to two years from the rule’s publication in the Federal Register. As a result of these recent developments, future implementation of the June 2015 rule is uncertain at this time but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, our operations as well as our exploration and production customers’ drilling programs could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
Spills. Our operations can result in the discharge of regulated substances, including NGLs, crude oil or other products. The Clean Water Act, as amended by the federal Oil Pollution Act of 1990, as amended, (“OPA”), and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into state waters or waters of the United States. The Clean Water Act and comparable state laws can impose substantial administrative, civil and criminal penalties for non-compliance including spills and other non-authorized discharges. The OPA subjects owners of covered facilities to strict joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release of oil. The PHMSA, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans that are to be used in the event of a spill incident.
In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our results of operations, financial position or expected cash flows.
Endangered Species Act. The Endangered Species Act, as amended, restricts activities that may affect endangered or threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may operate in areas that are currently designated as a habitat for endangered or threatened species or where the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened may occur in which event such one or more developments could cause us to incur additional costs, to develop habitat conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas. Moreover, such designation of previously unprotected species as threatened or endangered in areas where our oil and natural gas exploration and production customers operate could cause our

customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations, which could reduce demand for our services.
Climate Change. Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, the Subpart OOOOa standards have been subject to attempts by the EPA to stay portions of those standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. This rule, should it remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the United States State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on our assets.
Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such effects were to occur, our operations could be adversely affected in various ways, including damages to our facilities from powerful winds or rising waters, or increased costs for insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is

difficult to predict how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
Employee Health and Safety. We are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of the health and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. Historically, our costs for OSHA required activities, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances, have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
Employees
As of December 31, 2017, ETE and its consolidated subsidiaries employed an aggregate of 29,486 employees, 1,544 of which are represented by labor unions. We and our subsidiaries believe that our relations with our employees are satisfactory.
SEC Reporting
We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.
ITEM 1A.  RISK FACTORS
In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. ETP, Panhandle and Sunoco LP file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information. The risk factors set forth below, and those included in ETP’s, Panhandle’s and Sunoco LP’s Annual Reports, are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.
Risks Inherent in an Investment in Us
Cash distributions are not guaranteed and may fluctuate with our performance or other external factors.
The Parent company’s principal source of earnings and cash flow is cash distributions from ETP and Sunoco LP. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETP and Sunoco LP make to their partners. ETP and Sunoco LP may not be able to continue to make quarterly distributions at their current level or increase their quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP or Sunoco LP increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP or Sunoco LP to us.
Our ability to distribute cash received from ETP and Sunoco LP to our Unitholders is limited by a number of factors, including:
interest expense and principal payments on our indebtedness;
restrictions on distributions contained in any current or future debt agreements;
our general and administrative expenses;
expenses of our subsidiaries other than ETP and Sunoco LP, including tax liabilities of our corporate subsidiaries, if any; and
reserves our General Partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors, many of which are beyond our control or the control of our General Partner.
Our cash flow depends primarily on the cash distributions we receive from our partnership interests, including the incentive distribution rights, in ETP and Sunoco LP and, therefore, our cash flow is dependent upon the ability of ETP and Sunoco LP to make distributions in respect of those partnership interests.
We do not have any significant assets other than our partnership interests in ETP and Sunoco LP and our LNG business. As a result, our cash flow depends on the performance of ETP and Sunoco LP and their respective subsidiaries and ETP’s and Sunoco LP’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP and Sunoco LP.
The amount of cash that ETP and Sunoco LP can distribute to their partners, including us, each quarter depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter and will depend upon, among other things:
the amount of natural gas, NGLs, crude oil and refined products transported through ETP’s pipelines and gathering systems;
the level of throughput in processing and treating operations;
the fees charged and the margins realized by ETP and Sunoco LP for their services;
the price of natural gas, NGLs, crude oil and refined products;
the relationship between natural gas, NGL and crude oil prices;
the amount of cash distributions ETP receives with respect to the Sunoco LP common units that ETP or its subsidiaries own;
the weather in their respective operating areas;
the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;
the level of their respective operating costs and maintenance and integrity capital expenditures;
the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;
prevailing economic conditions; and
the level and results of their respective derivative activities.
In addition, the actual amount of cash that ETP and Sunoco LP will have available for distribution will also depend on other factors, such as:
the level of capital expenditures they make;
the level of costs related to litigation and regulatory compliance matters;
the cost of acquisitions, if any;
the levels of any margin calls that result from changes in commodity prices;
debt service requirements;
fluctuations in working capital needs;
their ability to borrow under their respective revolving credit facilities;
their ability to access capital markets;
restrictions on distributions contained in their respective debt agreements; and
the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct of their respective businesses.
ETE does not have any control over many of these factors, including the level of cash reserves established by the board of directors and ETP’s General Partners. Accordingly, we cannot guarantee that ETP and Sunoco LP will have sufficient available cash to pay a specific level of cash distributions to its partners.

Furthermore, Unitholders should be aware that the amount of cash that ETP and Sunoco LP have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, ETP and Sunoco LP may declare and/or pay cash distributions during periods when they record net losses. Please read “Risks Related to the Businesses of our Subsidiaries” included in this Item 1A for a discussion of further risks affecting ETP’s and Sunoco LP’s ability to generate distributable cash flow.
We may issue an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.
Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units, without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:
our Unitholders’ current proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each Common Unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding Common Unit may be diminished; and
the market price of our Common Units may decline.
In addition, ETP and Sunoco LP may sell an unlimited number of limited partner interests without the consent of the respective Unitholders, which will dilute existing interests of the respective Unitholders, including us. The issuance of additional Common Units or other equity securities by ETP or Sunoco LP will have essentially the same effects as detailed above.
ETP and Sunoco LP may issue additional Common Units, which may increase the risk that each Partnership will not have sufficient available cash to maintain or increase its per unit distribution level.
The partnership agreements of ETP and Sunoco LP allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by each respective partnership will have the following effects:
Unitholders’ current proportionate ownership interest in each partnership will decrease;
the amount of cash available for distribution on each common unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of each partnership’s common units may decline.
The payment of distributions on any additional units issued by ETP and Sunoco LP may increase the risk that either partnership may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.
Unitholders have limited voting rights and are not entitled to elect the General Partner or its directors. In addition, even if Unitholders are dissatisfied, they cannot easily remove the General Partner.
Unlike the holders of common stock in a corporation, Unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our General Partner and will have no right to elect our General Partner or the officers or directors of our General Partner on an annual or other continuing basis.
Furthermore, if our Unitholders are dissatisfied with the performance of our General Partner, they may be unable to remove our General Partner. Our General Partner may not be removed except, among other things, upon the vote of the holders of at least 66 2/3% of our outstanding units. As of December 31, 2017, our directors and executive officers directly or indirectly own approximately 27% of our outstanding Common Units. It will be particularly difficult for our General Partner to be removed without the consent of our directors and executive officers. As a result, the price at which our Common Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

Furthermore, Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the General Partner and its affiliates, cannot be voted on any matter.
Our General Partner may, in its sole discretion, approve the issuance of partnership securities and specify the terms of such partnership securities.
Pursuant to our partnership agreement, our General Partner has the ability, in its sole discretion and without the approval of the Unitholders, to approve the issuance of securities by the Partnership at any time and to specify the terms and conditions of such securities. The securities authorized to be issued may be issued in one or more classes or series, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of partnership securities), as shall be determined by our General Partner, including:
the right to share in the Partnership’s profits and losses;
the right to share in the Partnership’s distributions;
the rights upon dissolution and liquidation of the Partnership;
whether, and the terms upon which, the Partnership may redeem the securities;
whether the securities will be issued, evidenced by certificates and assigned or transferred; and
the right, if any, of the security to vote on matters relating to the Partnership, including matters relating to the relative rights, preferences and privileges of such security.
Please see “—We may issue an unlimited number of limited partner interests without the consent of our Unitholders, which will dilute Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.” above.
The control of our General Partner may be transferred to a third party without Unitholder consent.
The General Partner may transfer its general partner interest to a third party without the consent of the Unitholders. Furthermore, the members of our General Partner may transfer all or part of their ownership interest in our General Partner to a third party without the consent of the Unitholders. Any new owner or owners of our General Partner or the general partner of the General Partner would be in a position to replace the directors and officers of our General Partner with its own choices and to control the decisions made and actions taken by the board of directors and officers.
We are dependent on third parties, including key personnel of ETP under a shared services agreement, to provide the financial, accounting, administrative and legal services necessary to operate our business.
We rely on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETP’s midstream business. Mr. Warren has been integral to the success of ETP’s midstream and intrastate transportation and storage businesses because of his ability to identify and develop strategic business opportunities. Losing the leadership of Mr. Warren could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.
ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.
Cost reimbursements due to our General Partner may be substantial and may reduce our ability to pay the distributions to our Unitholders.
Prior to making any distributions to our Unitholders, we will reimburse our General Partner for all expenses it has incurred on our behalf. In addition, our General Partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our General Partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to our Unitholders. Our General Partner has sole discretion to determine the amount of these expenses and fees.
In addition, under Delaware partnership law, our General Partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our General Partner.

To the extent our General Partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our General Partner, our General Partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash available for distribution to our Unitholders and cause the value of our Common Units to decline.
A reduction in ETP’s or Sunoco LP’s distributions will disproportionately affect the amount of cash distributions to which ETE is entitled.
ETE indirectly owns all of the IDRs of ETP and Sunoco LP. These IDRs entitle the holder to receive increasing percentages of total cash distributions made by each of ETP and Sunoco LP as such entity reaches established target cash distribution levels as specified in its partnership agreement. ETE currently receives its pro rata share of cash distributions from ETP and Sunoco LP based on the highest sharing level of 48% and 50% in respect of the ETP IDRs and Sunoco LP IDRs, respectively.
A decrease in the amount of distributions by ETP to ETE to less than $0.2638 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from ETP above $0.0958 per unit per quarter from 48% to 35%, and a decrease in the amount of distributions by Sunoco LP to ETE to less than $0.6563 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from Sunoco LP above $0.5469 per unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash distributions from the ETP or Sunoco LP would have the effect of disproportionately reducing the amount of all distributions that ETE and ETP receive, based on their ownership interest in the IDRs as compared to cash distributions they receive from their general partner interest and common units in such entity.
The consolidated debt level and debt agreements of ETP and Sunoco LP and those of their subsidiaries may limit the distributions we receive from ETP and Sunoco LP, as well as our future financial and operating flexibility.
ETP’s and Sunoco LP’s levels of indebtedness affect their operations in several ways, including, among other things:
a significant portion of ETP’s and Sunoco LP’s and their subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions to us;
covenants contained in ETP’s and Sunoco LP’s and their subsidiaries’ existing debt agreements require ETP, Sunoco LP and their subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;
ETP’s and Sunoco LP’s and their subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
ETP and Sunoco LP may be at a competitive disadvantage relative to similar companies that have less debt;
ETP and Sunoco LP may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels;
failure by ETP, Sunoco LP or their subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETP’s and Sunoco LP’s ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay distributions to us and their unitholders.
We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt at maturity.
Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our Available Cash (as defined in our partnership agreement) to our Unitholders of record and our General Partner. Available Cash is generally all of our cash on hand as of the end of a quarter, adjusted for cash distributions and net changes to reserves. Our General Partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating subsidiaries in amounts it determines in its reasonable discretion to be necessary or appropriate:
to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures and for our anticipated future credit needs);
to provide funds for distributions to our Unitholders and our General Partner for any one or more of the next four calendar quarters; or
to comply with applicable law or any of our loan or other agreements.

A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.
A downgrade of our credit ratings might increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:
economic downturns;
deteriorating capital market conditions;
declining market prices for crude oil, natural gas, NGLs and other commodities;
terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Our subsidiaries are not prohibited from competing with us.
Neither our partnership agreement nor the partnership agreements of our subsidiaries, including ETP and Sunoco LP, prohibit our subsidiaries from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.
Capital projects will require significant amounts of debt and equity financing, which may not be available to ETP on acceptable terms, or at all.
ETP plans to fund its growth capital expenditures, including any new future pipeline construction projects and improvements or repairs to existing facilities that ETP may undertake, with proceeds from sales of ETP’s debt and equity securities and borrowings under its revolving credit facility; however, ETP cannot be certain that it will be able to issue debt and equity securities on terms satisfactory to it, or at all. In addition, ETP may be unable to obtain adequate funding under its current revolving credit facility because ETP’s lending counterparties may be unwilling or unable to meet their funding obligations. If ETP is unable to finance its expansion projects as expected, ETP could be required to seek alternative financing, the terms of which may not be attractive to ETP, or to revise or cancel its expansion plans.
A significant increase in ETP’s indebtedness that is proportionately greater than ETP’s issuance of equity could negatively impact ETP’s credit ratings or its ability to remain in compliance with the financial covenants under its revolving credit agreement, which could have a material adverse effect on ETP’s financial condition, results of operations and cash flows.
Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates. Approximately $9.86 billion of our consolidated debt as of December 31, 2017 bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates. We manage a portion of our interest rate exposures by utilizing interest rate swaps.
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment opportunities may cause the trading price of our Common Units to decline.
Unitholders may have liability to repay distributions.
Under certain circumstances, Unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law, will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other than the partnership interests and the equity in our subsidiaries. As a result, our ability to pay distributions to our Unitholders and to service our debt depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. If we are unable to obtain funds from our subsidiaries we may not be able to pay distributions to our Unitholders or to pay interest or principal on our debt when due.
Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.
Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Our partnership agreement allows the general partner to incur obligations on our behalf that are expressly non-recourse to the general partner. The general partner has entered into such limited recourse obligations in most instances involving payment liability and intends to do so in the future.
In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.
Our debt level and debt agreements may limit our ability to make distributions to Unitholders and may limit our future financial and operating flexibility and may require asset sales.
As of December 31, 2017, we had approximately $6.70 billion of debt on a stand-alone basis and approximately $44.08 billion of consolidated debt, excluding the debt of our joint ventures. Our level of indebtedness affects our operations in several ways, including, among other things:
a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;
covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;
our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or limited liability company purposes, as applicable, may be limited;
we may be at a competitive disadvantage relative to similar companies that have less debt;
we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and
failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.
In order for us to manage our debt levels, we may need to sell assets, issue additional equity securities, reduce the cash distributions we pay to our unitholders or a combination thereof. In the event that we sell assets, the future cash generating capacity of our remaining asset base may be diminished. In the event that we issue additional equity securities, we may need to issue these securities at a time when our common unit price is depressed and therefore we may not receive favorable prices for our common units or favorable prices or terms for other types of equity securities. In the event we reduce cash distributions on our common units, the public trading price of our common units could decline significantly.
Our General Partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 90% of our outstanding units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2017, the directors and executive officers of our General Partner owned approximately 27% of our Common Units.

Litigation commenced by WMB against ETE and its affiliates could cause ETE to incur substantial costs, may present material distractions and, if decided adverse to ETE, could negatively impact ETE’s financial position and credit ratings.
WMB filed a complaint against ETE and its affiliates in the Delaware Court of Chancery, alleging that the defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates.  Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the merger agreement by ETE on June 29, 2016, WMB filed a notice of appeal to the Supreme Court of Delaware.  WMB filed an amended complaint on September 16, 2016 and seeks a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement. The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and seek a $1.48 billion termination fee under the Merger Agreement and additional damages caused by WMB’s misconduct. These damages claims are based on the alleged breaches of the Merger Agreement, as well as new allegations that WMB breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On September 29, 2016, WMB filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on WMB’s motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision.  On January 11, 2017, the parties held oral argument before the Delaware Supreme Court on WMB’s appeal of the June 24 ruling. The Delaware Supreme Court has taken the matter under advisement. These lawsuits could result in substantial costs to ETE, including litigation costs and settlement costs. ETE believes that the time required by the management of ETE and its counsel to defend against the allegations made by WMB in the litigation against ETE and its affiliates is likely to be substantial and the time required by the officers and employees of LE GP, assuming WMB actively pursues such litigation, is also likely to be substantial. The defense or settlement of any lawsuit or claim that remains unresolved may result in negative media attention, and may adversely affect ETE’s business, reputation, financial condition, results of operations, cash flows and market price.
Risks Related to Conflicts of Interest
Although we control ETP and Sunoco LP through our ownership of their general partners, ETP’s and Sunoco LP’s general partners owe fiduciary duties to ETP and ETP’s unitholders and Sunoco LP and Sunoco LP’s unitholders, respectively, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and ETP and Sunoco LP and their respective limited partners, on the other hand. The directors and officers of ETP’s and Sunoco LP’s General Partners have fiduciary duties to manage ETP and Sunoco LP, respectively, in a manner beneficial to us. At the same time, the General Partners have fiduciary duties to manage ETP and Sunoco LP in a manner beneficial to ETP and Sunoco LP and their respective limited partners. The boards of directors of ETP’s and Sunoco LP’s General Partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.
For example, conflicts of interest with ETP and Sunoco LP may arise in the following situations:
the allocation of shared overhead expenses to ETP, Sunoco LP and us;
the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETP and Sunoco LP, on the other hand;
the determination of the amount of cash to be distributed to ETP’s and Sunoco LP’s partners and the amount of cash to be reserved for the future conduct of ETP’s and Sunoco LP’s businesses;
the determination whether to make borrowings under ETP’s and Sunoco LP’s revolving credit facilities to pay distributions to their respective partners;
the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of independently of ETP and Sunoco LP is made available for ETP and Sunoco LP to pursue; and
any decision we make in the future to engage in business activities independent of ETP and Sunoco LP.

The fiduciary duties of our General Partner’s officers and directors may conflict with those of ETP’s or Sunoco LP’s respective general partners.
Conflicts of interest may arise because of the relationships among ETP, Sunoco LP, their general partners and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our General Partner’s directors are also directors and officers of ETP’s general partner or Sunoco LP’s general partner, and have fiduciary duties to manage the respective businesses of ETP and Sunoco LP in a manner beneficial to ETP, Sunoco LP and their respective Unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.
Potential conflicts of interest may arise among our General Partner, its affiliates and us. Our General Partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.
Conflicts of interest may arise among our General Partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:
Our General Partner is allowed to take into account the interests of parties other than us, including ETP and Sunoco LP and their respective affiliates and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.
Our General Partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
Our General Partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.
Our General Partner determines which costs it and its affiliates have incurred are reimbursable by us.
Our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.
Our General Partner controls the enforcement of obligations owed to us by it and its affiliates.
Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our partnership agreement limits our General Partner’s fiduciary duties to us and restricts the remedies available for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
provides that our General Partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit and Conflicts Committee of the board of directors of our General Partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
provides that unless our General Partner has acted in bad faith, the action taken by our General Partner shall not constitute a breach of its fiduciary duty;
provides that our General Partner may resolve any conflicts of interest involving us and our General Partner and its affiliates, and any resolution of a conflict of interest by our General Partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and will not constitute a breach of the partnership agreement;

provides that our General Partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such resolution by appointing a conflicts committee of the General Partner’s board of directors composed of two or more independent directors to consider such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee shall be conclusively deemed “fair and reasonable” to us; and
provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
The general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our Unitholders.
Our partnership agreement requires the general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, our partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.
Risks Related to the Businesses of our Subsidiaries
Since our cash flows consist exclusively of distributions from our subsidiaries, risks to the businesses of our subsidiaries are also risks to us. We have set forth below risks to the businesses of our subsidiaries, the occurrence of which could have a negative impact on their respective financial performance and decrease the amount of cash they are able to distribute to us.
ETP does not control, and therefore may not be able to cause or prevent certain actions by, certain of its joint ventures.
Certain of ETP’s joint ventures have their own governing boards, and ETP may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for ETP to cause the joint venture entity to take actions that ETP believes would be in their or the joint venture’s best interests. Likewise, ETP may be unable to prevent actions of the joint venture.
ETP and Sunoco LP are exposed to the credit risk of their respective customers and derivative counterparties, and an increase in the nonpayment and nonperformance by their respective customers or derivative counterparties could reduce their respective ability to make distributions to their Unitholders, including to us.
The risks of nonpayment and nonperformance by ETP’s and Sunoco LP’s respective customers are a major concern in their respective businesses. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP and Sunoco LP are subject to risks of loss resulting from nonpayment or nonperformance by their respective customers, especially during the current low commodity price environment impacting many oil and gas producers. As a result, the current commodity price volatility and the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s and Sunoco LP’s customers. To the extent one or more of our customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our Unitholders. Any substantial increase in the nonpayment and nonperformance by ETP’s or Sunoco LP’s customers could have a material adverse effect on ETP’s or Sunoco LP’s respective results of operations and operating cash flows.
The use of derivative financial instruments could result in material financial losses by ETP and Sunoco LP.
From time to time, ETP and Sunoco LP have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by their trading, marketing and/or system optimization activities. To the extent that either ETP or Sunoco LP hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change favorably. In addition, ETP’s and Sunoco LP’s derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to ETP’s or Sunoco LP’s physical or financial positions, or internal hedging policies and procedures are not followed.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.
In addition, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.
The inability to continue to access lands owned by third parties, including tribal lands, could adversely affect ETP’s and Sunoco LP’s ability to operate and adversely affect their financial results.
ETP’s ability to operate its pipeline systems and terminal facilities on certain lands owned by third parties, including lands held in trust by the United States for the benefit of a Native American tribe, will depend on their success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. Securing extensions of existing and any additional rights-of-way is also critical to ETP’s ability to pursue expansion projects. ETP cannot provide any assurance that they will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants or that all of the rights-of-way will be obtainable in a timely fashion. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively. ETP’s financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.
Further, whether ETP has the power of eminent domain for its pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state. In either case, ETP must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect ETP’s business if they were to lose the right to use or occupy the property on which their pipelines are located. For example, following a recent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. Any loss of rights with respect to ETP’s real property, through its inability to renew right-of-way contracts or otherwise, could have a material adverse effect on its business, results of operations, financial condition and ability to make cash distributions.
In addition, Sunoco LP does not own all of the land on which their retail service stations are located. Sunoco LP has rental agreements for approximately 35.2% of the company-operated retail service stations where Sunoco LP currently controls the real estate and has rental agreements for certain logistics facilities. As such, Sunoco LP is subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Sunoco LP is also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by Sunoco LP are leased from third parties for specific periods. Sunoco LP’s inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on its financial condition, results of operations and cash flows.
ETP and Sunoco LP may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.
ETP and Sunoco LP have strategies that contemplate growth through the development and acquisition of a wide range of midstream, retail and wholesale fuel distribution assets and other energy infrastructure assets while maintaining strong balance sheets. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP and Sunoco LP regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that ETP and Sunoco LP believe will present opportunities to realize synergies and increase cash flow.
Consistent with their strategies, managements of ETP and Sunoco LP may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP and Sunoco LP management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP and Sunoco LP believe it is the only party or one of a very limited number of potential buyers

in negotiations with the potential seller. We cannot assure that ETP’s or Sunoco LP’s acquisition efforts will be successful or that any acquisition will be completed on favorable terms.
In addition, ETP and Sunoco LP are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETP or Sunoco LP losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s and Sunoco LP’s ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETP’s and Sunoco LP’s results of operations.
An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2017, our consolidated balance sheets reflected $4.77 billion of goodwill and $6.12 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.
During the fourth quarter of 2017, we performed goodwill impairment tests on our reporting units and recognized goodwill impairments at both ETP and Sunoco LP. The goodwill impairments at ETP consisted of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations and $452 million in its all other operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. During the year 2017, Sunoco LP recorded a goodwill impairment charge of $102 million on its retail reporting unit.

During the fourth quarter of 2016, we performed goodwill impairment tests on our reporting units and recognized goodwill impairments at both ETP and Sunoco LP. The goodwill impairments recognized at ETP consisted of $638 million related to ETP’s interstate transportation and storage operations and $32 million related to ETP’s midstream operations. These impairments are primarily due to decreases in projected future revenues and cash flows driven by reduced volumes as a result of overall declining commodity prices and changes in the markets that these assets serve. During the fourth quarter of 2016, Sunoco LP recognized a goodwill impairment of $641 million in its retail reporting unit primarily due to changes in assumptions related to projected future revenues and cash flows from the dates this goodwill was originally recorded. During the fourth quarter of 2016, Sunoco LP also recognized a $32 million impairment on its Laredo Taco brand name intangible asset primarily due to changes in Sunoco LP’s construction plan for new-to-industry sites and decreases in sales volume in oil field producing regions where Sunoco LP has operations.
If ETP and Sunoco LP do not make acquisitions on economically acceptable terms, their future growth could be limited.
ETP’s and Sunoco LP’s results of operations and their ability to grow and to increase distributions to Unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.
ETP and Sunoco LP may be unable to make accretive acquisitions for any of the following reasons, among others:
inability to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
inability to raise financing for such acquisitions on economically acceptable terms; or
inability to outbid by competitors, some of which are substantially larger than ETP or Sunoco LP and may have greater financial resources and lower costs of capital.
Furthermore, even if ETP or Sunoco LP consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP or Sunoco LP may:
fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
decrease its liquidity by using a significant portion of its available cash or borrowing capacity to finance acquisitions;
significantly increase its interest expense or financial leverage if the acquisition is financed with additional debt;
encounter difficulties operating in new geographic areas or new lines of business;

incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which there is no indemnity or the indemnity is inadequate;
be unable to hire, train or retrain qualified personnel to manage and operate its growing business and assets;
less effectively manage its historical assets, due to the diversion of management’s attention from other business concerns; or
incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
If ETP and Sunoco LP consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETP and Sunoco LP determine the application of their funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that ETP and Sunoco LP will consider.
Integration of assets acquired in past acquisitions or future acquisitions with our existing business will be a complex and time-consuming process. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to our unitholders.
The difficulties of integrating past and future acquisitions with our business include, among other things:
operating a larger combined organization in new geographic areas and new lines of business;
hiring, training or retaining qualified personnel to manage and operate our growing business and assets;
integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;
diversion of management’s attention from our existing business;
assimilation of acquired assets and operations, including additional regulatory programs;
loss of customers or key employees;
maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and
integrating new technology systems for financial reporting.
If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions resulting in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.
Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems, and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, may not be observable even when an inspection is undertaken.
Legal actions related to the Dakota Access Pipeline could cause an interruption to operations, which could have an adverse effect on our business and results of operations.
On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. The USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. The Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (the “Court”) against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline and claimed violations of the National Historic Preservation Act (“NHPA”). Dakota Access intervened in the case.
In February 2017, the Department of the Army delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. The SRST and Cheyenne River Sioux Tribe (“CRST”) (which had intervened in the lawsuit brought by SRST), amended their complaints to incorporate religious freedom and other claims related to treaties and use of government property. The Oglala and

Yankton Sioux tribes, and various individual members, filed related lawsuits in opposition to the Dakota Access pipeline. These lawsuits have been consolidated into the action initiated by the SRST.
On June 14, 2017, the Court ruled that the USACE substantially complied with all relevant statutes in connection with the issuance of the permits and easement, but remanded to the USACE three discrete issues for further analysis and explanation of its prior determination under certain of these statutes. On October 11, 2017, the Court ruled that the pipeline could continue to transport crude oil during the pendency of the remand, but requested briefing from the parties as to whether any conditions on the continued operation of the pipeline during this period. On December 4, 2017, the Court determined to impose three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. Second, the Court directed Dakota Access to continue its work with the tribes and the USACE to revise and finalize its response planning for the section of the pipeline crossing Lake Oahe. Third, the Court directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information recommended by PHMSA.
While we believe that the pending lawsuits are unlikely to adversely affect the continued operation of the pipeline, we cannot assure this outcome. At this time, we cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
In addition, lawsuits of this nature could result in interruptions to construction or operations of future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business and results of operations.
Income from ETP’s midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs and crude oil that are beyond our control.
The prices for natural gas, NGLs and crude oil (including refined petroleum products) reflect market demand that fluctuates with changes in global and United States economic conditions and other factors, including:
the level of domestic natural gas, NGL, and crude oil production;
the level of natural gas, NGL, and crude oil imports and exports, including liquefied natural gas;
actions taken by natural gas and oil producing nations;
instability or other events affecting natural gas and oil producing nations;
the impact of weather and other events of nature on the demand for natural gas, NGLs and crude oil;
the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;
the price, availability and marketing of competitive fuels;
the demand for electricity;
activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of oil and natural gas;
the cost of capital needed to maintain or increase production levels and to construct and expand facilities
the impact of energy conservation and fuel efficiency efforts; and
the extent of governmental regulation, taxation, fees and duties.
In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and we expect this volatility to continue.
Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs or crude oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGLs and crude oil commodities could materially affect our profitability.
ETP is affected by competition from other midstream, transportation and storage and retail marketing companies.
We experience competition in all of our business segments. With respect to ETP’s midstream operations, ETP competes for both natural gas supplies and customers for its services. Competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.
ETP’s natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas

and NGLs also compete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.
In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.
ETP’s crude oil and refined products pipeline operations face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in areas served by Sunoco Logistics’ pipelines. Further, our refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.
ETP may be unable to retain or replace existing midstream, transportation, terminalling and storagecustomers or volumes due to declining demand or increased competition in crude oil, natural gas and NGL markets, which would reduce revenues and limit future profitability.
The retention or replacement of existing customers and the volume of services that ETP provides at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of and demand for crude oil, natural gas, and NGLs in the markets we serve and competition from other service providers.
A significant portion of ETP’s sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in natural gas sales markets primarily on the basis of price.
ETP also receives a substantial portion of revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of their services are sold under long-term contracts for reserved service, they also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services, while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers’ business. If demand declines or competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.
Revenue from ETP’s NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. ETP receives substantially all of their transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to their transportation system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, ETP’s refined products storage revenues are primarily derived from fixed capacity arrangements between us and our customers, a portion of its revenue is derived from fungible storage and throughput arrangements, under which ETP’s revenue is more dependent upon demand for storage from its customers.
The volume of crude oil and products transported through ETP’s oil pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. A period of sustained increases in the price of crude oil or products supplied from or delivered to any of these areas could materially reduce demand for crude oil or products in these areas. In either case, the volumes of crude oil or products transported in our oil pipelines and terminal facilities could decline.
The loss of existing customers by ETP’s midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services customers purchase from them, or their inability to attract new customers and service volumes would negatively affect revenues, be detrimental to growth, and adversely affect results of operations.

ETP’s midstream facilities and transportation pipelines are attached to basins with naturally declining production, which it may not be able to replace with new sources of supply.
In order to maintain or increase throughput levels on ETP’s gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, ETP must continually contract for new natural gas supplies and natural gas transportation services.
A substantial portion of ETP’s assets, including its gathering systems and processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. ETP’s gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. ETP may not be able to obtain additional contracts for natural gas supplies for its natural gas gathering systems, and may be unable to maintain or increase the levels of natural gas throughput on its transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to its transportation pipelines or markets to which ETP’s systems connect. ETP has no control over the level of drilling activity in its areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, ETP has no control over producers or their production and contracting decisions.
While a substantial portion of ETP’s services are provided under long-term contracts for reserved service, it also provides service on an unreserved basis. The reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities may decline and may not be replaced by other sources of supply. A decrease in development or production activity could cause a decrease in the volume of unreserved services ETP provides and a decrease in the number and volume of its contracts for reserved transportation service over the long run, which in each case would adversely affect revenues and results of operations.
If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.
The profitability of certain activities in ETP’s natural gas gathering, processing, transportation and storage operations is largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.
For a portion of the natural gas gathered on ETP’s systems, they purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where they typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins realized under these arrangements decrease in periods of low natural gas prices.
ETP also enters into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which they agree to gather and process natural gas received from the producers.
Under percent-of-proceeds arrangements, ETP generally sells the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, ETP delivers an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes kept to third parties at market prices. Under these arrangements, ETP’s revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on ETP’s revenues and results of operations.
Under keep-whole arrangements, ETP generally sells the NGLs produced from their gathering and processing operations at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, ETP must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, gross margins generally decrease when the price of natural gas increases relative to the price of NGLs.
When ETP processes the gas for a fee under processing fee agreements, they may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, ETP may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.
ETP also receives fees and retains gas in kind from natural gas transportation and storage customers. The fuel retention fees and the value of gas that ETP retains in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease these fuel retention fees and the value of retained gas.

In addition, ETP receives revenue from their off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of ETP’s off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could cause a decrease in demand for their off-gas processing and fractionation services and could have an adverse effect on their results of operations.
For ETP’s midstream operations, gross margin is generally analyzed based on fee-based margin (which includes revenues from processing fee arrangements) and non-fee based margin (which includes gross margin earned on percent-of-proceeds and keep-whole arrangements). For the years ended December 31, 2017, 2016 and 2015, gross margin from ETP’s midstream operations totaled $2.18 billion, $1.80 billion, and $1.79 billion, respectively, of which fee-based revenues constituted 78%, 86% and 88%, respectively, and non-fee based margin constituted 22%, 14% and 12%, respectively. The amount of gross margin earned by ETP’s midstream operations from fee-based and non-fee based arrangements (individually and as a percentage of total revenues) will be impacted by the volumes associated with both types of arrangements, as well as commodity prices; therefore, the dollar amounts and the relative magnitude of gross margin from fee-based and non-fee based arrangements in future periods may be significantly different from results reported in previous periods.
ETP’s revenues depend on its customers’ ability to use ETP’s pipelines and third-party pipelines over which we have no control.
ETP’s natural gas transportation, storage and NGL businesses depend, in part, on their customers’ ability to obtain access to pipelines to deliver gas to and receive gas from ETP. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third-party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material adverse effect on ETP’s ability, and the ability of their customers, to transport natural gas to and from their pipelines and facilities and a corresponding material adverse effect on their transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from ETP’s s facilities affect the utilization and value of their storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on storage revenues.
Shippers using ETP’s oil pipelines and terminals are also dependent upon their pipelines and connections to third-party pipelines to receive and deliver crude oil and products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in ETP’s pipelines or through their terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to ETP existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in their pipelines or through their terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on ETP’s results of operations, financial position, or cash flows.
If ETP does not continue to construct new pipelines, their future growth could be limited.
ETP’s results of operations and their ability to grow and to increase distributable cash flow per unit will depend, in part, on their ability to construct pipelines that are accretive to their respective distributable cash flow. ETP may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:
inability to identify pipeline construction opportunities with favorable projected financial returns;
inability to raise financing for its identified pipeline construction opportunities; or
inability to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or for other reasons.
Furthermore, even if ETP constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or fail to achieve results projected prior to commencement of construction.
Expanding ETP’s business by constructing new pipelines and related facilities subjects ETP to risks.
One of the ways that ETP has grown their business is through the construction of additions to existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline and related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond ETP’s control and requires the expenditure of significant amounts of capital to be financed through borrowings, the issuance of additional equity or from operating cash flow. If ETP undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. A variety of factors outside ETP’s control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors may result in increased costs or delays

in construction. Cost overruns or delays in completing a project could have a material adverse effect on ETP’s results of operations and cash flows. Moreover, revenues may not increase immediately following the completion of a particular project. For instance, if ETP builds a new pipeline, the construction will occur over an extended period of time, but ETP may not materially increase its revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, ETP may construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s expected investment return, which could adversely affect its results of operations and financial condition.
ETP depends on certain key producers for a significant portion of their supplies of natural gas. The loss of, or reduction in, any of these key producers could adversely affect ETP’s business and operating results.
ETP relies on a limited number of producers for a significant portion of their natural gas supplies. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, ETP will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. ETP may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on ETP’s business, results of operations, and financial condition.
ETP depends on key customers to transport natural gas through their pipelines.
ETP relies on a limited number of major shippers to transport certain minimum volumes of natural gas on their respective pipelines. The failure of the major shippers on ETP’s or their joint ventures’ pipelines or of other key customers to fulfill their contractual obligations under these contracts could have a material adverse effect on the cash flow and results of operations of us, ETP or their joint ventures, as applicable, were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.
ETP’s contract compression operations depend on particular suppliers and are vulnerable to parts and equipment shortages and price increases, which could have a negative impact on results of operations.
The principal manufacturers of components for ETP’s natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers and Ariel Corporation for compressors and frames. ETP’s reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. ETP also relies primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble its compression units. ETP does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships.
A material decrease in demand or distribution of crude oil available for transport through ETP’s pipelines or terminal facilities could materially and adversely affect our results of operations, financial position, or cash flows.
The volume of crude oil transported through ETP’s crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by its assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to ETP’s customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in ETP’s crude oil pipelines and terminal facilities could decline, and it could likely be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all. If ETP is unable to replace any significant volume declines with additional volumes from other sources, its results of operations, financial position, or cash flows could be materially and adversely affected.
An interruption of supply of crude oil to ETP’s facilities could materially and adversely affect our results of operations and revenues.
While ETP is well positioned to transport and receive crude oil by pipeline, marine transport and trucks, rail transportation also serves as a critical link in the supply of domestic crude oil production to United States refiners, especially for crude oil from regions such as the Bakken that are not sourced near pipelines or waterways that connect to all of the major United States refining centers. Federal regulators have issued a safety advisory warning that Bakken crude oil may be more volatile than many other North American crude oils and reinforcing the requirement to properly test, characterize, classify, and, if applicable, sufficiently degasify hazardous materials prior to and during transportation. The domestic crude oil received by our facilities, especially from the Bakken region, may be transported by railroad. If the ability to transport crude oil by rail is disrupted because of accidents,

weather interruptions, governmental regulation, congestion on rail lines, terrorism, other third-party action or casualty or other events, then ETP could experience an interruption of supply or delivery or an increased cost of receiving crude oil, and could experience a decline in volumes received. Recent railcar accidents in Quebec, Alabama, North Dakota, Pennsylvania and Virginia, in each case involving trains carrying crude oil from the Bakken region, have led to increased legislative and regulatory scrutiny over the safety of transporting crude oil by rail. In 2015, the DOT, through the PHMSA, issued a rule implementing new rail car standards and railroad operating procedures. Changing operating practices, as well as new regulations on tank car standards and shipper classifications, could increase the time required to move crude oil from production areas of facilities, increase the cost of rail transportation, and decrease the efficiency of transportation of crude oil by rail, any of which could materially reduce the volume of crude oil received by rail and adversely affect our financial condition, results of operations, and cash flows.
A portion of ETP’s general and administrative services have been outsourced to third-party service providers. Fraudulent activity or misuse of proprietary data involving its outsourcing partners could expose us to additional liability.
ETP utilizes both affiliate entities and third parties in the processing of its information and data. Breaches of its security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about ETP or its customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose ETP to a risk of loss or misuse of this information, result in litigation and potential liability for ETP, lead to reputational damage, increase compliance costs, or otherwise harm its business.
Sunoco LP is entirely dependent upon third parties for the supply of refined products such as gasoline and diesel for its retail marketing business.
Sunoco LP is required to purchase refined products from third party sources, including the joint venture that acquired Sunoco, Inc.’s Philadelphia refinery. Sunoco LP may also need to contract for new ships, barges, pipelines or terminals which it has not historically used to transport these products to its markets. The inability to acquire refined products and any required transportation services at favorable prices may adversely affect Sunoco LP’s business and results of operations.
A significant decrease in demand for motor fuel, including increased consumer preference for alternative motor fuels or improvements in fuel efficiency, in the areas Sunoco LP serves would reduce their ability to make distributions to unitholders.
Sales of refined motor fuels account for approximately 93% of Sunoco LP’s total revenues and 62% of continuing operations gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and their ability to make or increase distributions to unitholders. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience declines in their profit margin if fuel distribution volumes decrease.
Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change customers' shopping habits or lead to new forms of fueling destinations or new competitive pressures.
New technologies have been developed and governmental mandates have been implemented to improve fuel efficiency, which may result in decreased demand for petroleum-based fuel. Any of these outcomes could result in fewer visits to Sunoco LP’s convenience stores or independently operated commission agents and dealer locations, a reduction in demand from their wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit margins, any of which could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.

The industries in which Sunoco LP operates are subject to seasonal trends, which may cause our operating costs to fluctuate, affecting our cash flow.

Sunoco LP relies in part on customer travel and spending patterns, and may experience more demand for gasoline in the late spring and summer months than during the fall and winter. Travel, recreation and construction are typically higher in these months in the geographic areas in which Sunoco LP or its commission agents and dealers operate, increasing the demand for motor fuel that they sell and distribute. Therefore, Sunoco LP’s revenues and cash flows are typically higher in the second and third quarters of our fiscal year. As a result, Sunoco LP’s results from operations may vary widely from period to period, affecting Sunoco LP’s cash flow.

Sunoco LP’s financial condition and results of operations are influenced by changes in the prices of motor fuel, which may adversely impact margins, customers’ financial condition and the availability of trade credit.
Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.
Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.
The dangers inherent in the storage and transportation of motor fuel could cause disruptions in Sunoco LP’s operations and could expose them to potentially significant losses, costs or liabilities.
Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a material adverse effect on its business, financial condition, results of operations and cash available for distribution to unitholders.
Sunoco LP’s fuel storage terminals are subject to operational and business risks which may adversely affect their financial condition, results of operations, cash flows and ability to make distributions to unitholders.
Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following:
the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;
the dependence on third parties to supply their fuel storage terminals;
outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;
the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;
the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;
the effects of a sustained recession or other adverse economic conditions;
the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel storage terminals or reduce the demand by consumers for petroleum products;
competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and
climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for our storage services.
The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s business, financial condition, results of operations, cash flows and ability to make distributions to unitholders.
Negative events or developments associated with Sunoco LP’s branded suppliers could have an adverse impact on its revenues.
Sunoco LP believes that the success of its operations is dependent, in part, on the continuing favorable reputation, market value, and name recognition associated with the motor fuel brands sold at Sunoco LP’s convenience stores and at stores operated by its independent, branded dealers and commission agents. Erosion of the value of those brands could have an adverse impact on the

volumes of motor fuel Sunoco LP distributes, which in turn could have a material adverse effect on its business, financial condition, results of operations and ability to make distributions to its unitholders.
The wholesale motor fuel distribution industry and convenience store industry are characterized by intense competition and fragmentation and impacted by new entrants. Failure to effectively compete could result in lower margins.
The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-added, reliable services and to control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.
The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently operated commission agents and dealers sell in stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.
In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse effect on its business, results of operations and cash available for distribution to unitholders.
Sunoco LP expect to generate a significant portion of its motor fuel sales under a fuel supply agreement with 7-Eleven, and any loss, or change in the economic terms, of such arrangement could adversely affect Sunoco LP’s business, financial condition and results of operations.
Sunoco LP expect that a significant portion of its motor fuel sales in 2018 will be derived from its fuel supply agreement with 7-Eleven. The 7-Eleven fuel supply agreement is a 15-year fixed margin, “take or pay” fuel supply arrangement with certain affiliates of 7-Eleven. The loss or change in economics of such arrangement and the inability to enter into new contracts on similar economically acceptable terms could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations.
Wholesale cost increases in tobacco products, including excise tax increases on cigarettes, could adversely impact Sunoco LP’s revenues and profitability.
Significant increases in wholesale cigarette costs and tax increases on cigarettes may have an adverse effect on unit demand for cigarettes. Cigarettes are subject to substantial and increasing excise taxes at both a state and federal level. Sunoco LP cannot predict whether this trend will continue into the future. Increased excise taxes may result in declines in overall sales volume and reduced gross profit percent, due to lower consumption levels and to a shift in consumer purchases from the premium to the non-premium or discount segments or to other lower-priced tobacco products or to the import of cigarettes from countries with lower, or no, excise taxes on such items.
Currently, major cigarette manufacturers offer rebates to retailers. Sunoco LP includes these rebates as a component of its gross margin from sales of cigarettes. In the event these rebates are no longer offered, or decreased, Sunoco LP’s wholesale cigarette costs will increase accordingly. In general, Sunoco LP attempts to pass price increases on to its customers. However, due to competitive pressures in our markets, it may not be able to do so. These factors could materially impact Sunoco LP’s retail price of cigarettes, cigarette unit volume and revenues, merchandise gross profit and overall customer traffic, which could in turn have a material adverse effect on Sunoco LP’s business and results of operations.

Failure to comply with state laws regulating the sale of alcohol and cigarettes may result in the loss of necessary licenses and the imposition of fines and penalties, which could have a material adverse effect on Sunoco LP’s business.
State laws regulate the sale of alcohol and cigarettes. A violation of or change in these laws could adversely affect Sunoco LP’s business, financial condition and results of operations because state and local regulatory agencies have the power to approve, revoke, suspend or deny applications for, and renewals of, permits and licenses relating to the sale of these products and can also seek other remedies. Such a loss or imposition could have a material adverse effect on Sunoco LP’s business and results of operations.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. A disruption in supply or a change in either relationship could have a material adverse effect on its business.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to unitholders.
Sunoco LP may be subject to adverse publicity resulting from concerns over food quality, product safety, health or other negative events or developments that could cause consumers to avoid its retail locations or independently operated commission agent or dealer locations.
Sunoco LP may be the subject of complaints or litigation arising from food-related illness or product safety which could have a negative impact on its business. Negative publicity, regardless of whether the allegations are valid, concerning food quality, food safety or other health concerns, food service facilities, employee relations or other matters related to its operations may materially adversely affect demand for its food and other products and could result in a decrease in customer traffic to its retail stores or independently operated commission agent or dealer locations.
It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name recognition.
Sunoco LP has outsourced various functions related to its retail marketing business to third-party service providers, which decreases its control over the performance of these functions. Disruptions or delays of its third-party outsourcing partners could result in increased costs, or may adversely affect service levels. Fraudulent activity or misuse of proprietary data involving its outsourcing partners could expose it to additional liability.
Sunoco LP has previously outsourced various functions related to its retail marketing business to third parties and expects to continue this practice with other functions in the future. While outsourcing arrangements may lower its cost of operations, they also reduce its direct control over the services rendered. It is uncertain what effect such diminished control will have on the quality or quantity of products delivered or services rendered, on its ability to quickly respond to changing market conditions, or on its ability to ensure compliance with all applicable domestic and foreign laws and regulations. Sunoco LP believes that it conducts appropriate due diligence before entering into agreements with its outsourcing partners. Sunoco LP relies on its outsourcing partners to provide services on a timely and effective basis. Although Sunoco LP continuously monitor the performance of these third parties and maintain contingency plans in case they are unable to perform as agreed, it does not ultimately control the performance of its outsourcing partners. Much of its outsourcing takes place in developing countries and, as a result, may be subject to geopolitical uncertainty. The failure of one or more of its third-party outsourcing partners to provide the expected services on a timely basis at the prices Sunoco LP expect, or as required by contract, due to events such as regional economic, business, environmental or political events, information technology system failures, or military actions, could result in significant disruptions and costs to its operations, which could materially adversely affect its business, financial condition, operating results and cash flow. Sunoco LP’s failure to generate significant cost savings from these outsourcing initiatives could adversely affect its profitability and weaken its competitive position. Additionally, if the implementation of its outsourcing initiatives is disruptive to its retail marketing business, Sunoco LP could experience transaction errors, processing inefficiencies, and the loss of sales and customers, which could cause its business and results of operations to suffer. As a result of these outsourcing initiatives, more third parties are involved in processing its retail marketing information and data. Breaches of security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about its retail marketing business or its clients, including the potential loss or disclosure of such information or data as a result of fraud or other forms of

deception, could expose it to a risk of loss or misuse of this information, result in litigation and potential liability for it, lead to reputational damage to the Sunoco brand, increase its compliance costs, or otherwise harm its business.
ETP’s interstate natural gas pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which may prevent us from fully recovering our costs.
Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of ETP’s interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.
ETP is required to file tariff rates (also known as recourse rates) with the FERC that shippers may elect to pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. ETP must also file with the FERC all negotiated rates that do not conform to our tariff rates and all changes to our tariff or negotiated rates. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.
The FERC may review existing tariff rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against ETP and find that its rates were not just and reasonable or unduly discriminatory, the maximum rates customers could elect to pay ETP may be reduced and the reduction could have an adverse effect on our revenues and results of operations.
The costs of ETP’s interstate pipeline operations may increase and ETP may not be able to recover all of those costs due to FERC regulation of its rates. If ETP proposes to change its tariff rates, its proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit ETP’s proposed changes if ETP is unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. ETP also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or ETP may be constrained by competitive factors from charging their tariff rates.
To the extent ETP’s costs increase in an amount greater than its revenues increase, or there is a lag between its cost increases and ability to file for and obtain rate increases, ETP’s operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. ETP cannot guarantee that its interstate pipelines will be able to recover all of their costs through existing or future rates.
The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. It is currently the FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, to the extent that the ultimate owners have an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Under the FERC’s policy, ETP thus remains eligible to include an income tax allowance in the tariff rates ETP charges for interstate natural gas transportation. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC issued the Notice of Inquiry in response to a remand from the United States Court of Appeals for the D.C. Circuit in United Airlines v. FERC, in which the court determined that FERC had not justified its conclusion that an oil pipeline organized as a partnership would not “double recover” its taxes under the current policy by both including a tax allowance in its cost-based rates and earning a return on equity calculated on a pre-tax basis. FERC requested comments regarding how to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect to the notice of inquiry ended on April 7, 2017. The outcome of the inquiry is still pending. ETP cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on either income tax allowances or return on equity calculations for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as part of a master limited partnership or decreases the return on equity for such pipelines could result in an adverse impact on ETP’s revenues associated with the transportation and storage services ETP provides pursuant to cost-based rates.
Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. Following the 2017 Tax Cuts and Jobs Act being signed into law, filings have been made at FERC requesting that FERC require pipelines to lower their transportation rates to account for lower taxes. Following the effective date of the law, the FERC orders granting certificates to construct proposed pipeline facilities have directed pipelines proposing new rates for service on those facilities to re-file such rates so that the rates reflect the reduction in the corporate tax rate, and

FERC has issued data requests in pending certificate proceedings for proposed pipeline facilities requesting pipelines to explain the impacts of the reduction in the corporate tax rate on the rate proposals in those proceedings and to provide re-calculated initial rates for service on the proposed pipeline facilities. FERC may enact other regulations or issue further requests to pipelines regarding the impact of the corporate tax rate change on the rates. The FERC’s establishment of a just and reasonable rate is based on many components, and the reduction in the corporate tax rate may impact two of such components: the allowance for income taxes and the amount for accumulated deferred income taxes. Because ETP’s existing jurisdictional rates were established based on a higher corporate tax rate, FERC or ETP’s shippers may challenge these rates in the future, and the resulting new rate may be lower than the rates ETP currently charges.
ETP’s interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect its business and operations.
In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of ETP’s interstate natural gas pipelines, including:
operating terms and conditions of service;
the types of services interstate pipelines may or must offer their customers;
construction of new facilities;
acquisition, extension or abandonment of services or facilities;
reporting and information posting requirements;
accounts and records; and
relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
Compliance with these requirements can be costly and burdensome. In addition, ETP cannot guarantee that the FERC will authorize tariff changes and other activities it might propose to undertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof may impair the ability of ETP’s interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.
The current FERC Chairman announced in December 2017 that FERC will review its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. ETP is unable to predict what, if any, changes may be proposed that will affect its natural gas pipeline business or when such proposals, if any, might become effective. ETP does not expect that any change in this policy would affect them in a materially different manner than any other similarly sized natural gas pipeline company operating in the United States.
Rate regulation or market conditions may not allow ETP to recover the full amount of increases in the costs of its crude oil, NGL and products pipeline operations.
Transportation provided on ETP’s common carrier interstate crude oil, NGL and products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If ETP proposes new or changed rates, the FERC or interested persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The primary ratemaking methodology used by the FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. The FERC’s ratemaking methodologies may limit our ability to set rates based on our costs or may delay the use of rates that reflect increased costs. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior two years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules ended March 17, 2017. FERC has not yet taken any further action on the proposed rule. If the FERC’s indexing methodology changes, the new methodology could materially and adversely affect our financial condition, results of operations or cash flows.

Under the EPAct of 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could order us to reduce pipeline rates prospectively and to pay refunds to shippers.
If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.
State regulatory measures could adversely affect the business and operations of ETP’s midstream and intrastate pipeline and storage assets.
ETP’s midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects their business and the market for their products. The rates, terms and conditions of service for the interstate services they provide in their intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. ETP’s HPL System, East Texas pipeline, Oasis pipeline and ET Fuel System provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than ETP’s costs of service, their cash flow would be negatively affected.
ETP’s midstream and intrastate gas and oil transportation pipelines and their intrastate gas storage operations are subject to state regulation. All of the states in which they operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which ETP operates have ratable take statutes, which generally require gatherers to take, without undue discrimination, production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, ETP’s businesses may be adversely affected.
ETP’s intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the TRRC. Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.
ETP is subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations of state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.
Certain of ETP’s assets may become subject to regulation.
The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of extensive litigation and may be determined by the FERC on a case-by-case basis, although the FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.
Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Lone Star’s NGL Pipeline transports NGLs within the state of Texas and is subject to regulation by the TRRC. This NGLs transportation system offers services pursuant to an intrastate transportation tariff on file with the TRRC. In 2013, Lone Star’s NGL pipeline also commenced the interstate transportation of NGLs, which is subject to FERC’s jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992. Both intrastate and interstate NGL transportation services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a negotiated agreement; however, if FERC’s ratemaking methodologies were imposed, they may, among other things, delay the use of rates that reflect increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the rates, terms and conditions for shipments of crude oil, petroleum products and NGLs on our pipelines are subject to regulation by FERC if the NGLs are transported in interstate or foreign commerce, whether by our pipelines or other means of transportation.

Since we do not control the entire transportation path of all crude oil, petroleum products and NGLs on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
In addition, if any of our pipelines were found to have provided services or otherwise operated in violation of the NGA, NGPA, or ICA, this could result in the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to these assets.
ETP may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to authority under the NGPSA and HLPSA, as amended, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect HCAs which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas.
These regulations require operators of covered pipelines to:
perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline operations that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, in January 2017, PHMSA issued a final rule for hazardous liquid pipelines that significantly expands the reach of certain PHMSA integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a HCA. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register is uncertain given the recent change in Presidential Administrations. In a second example, in April 2016, PHMSA published a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressure (“MOAP”); and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements and also require consideration of seismicity in evaluating threats to pipelines. The changes adopted or proposed by these rulemakings or made in future legal requirements could have a material adverse effect on ETP’s results of operations and costs of transportation services.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
The NGPSA and HLPSA were amended by the 2011 Pipeline Safety Act. Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the MAOP of certain interstate natural gas transmission pipelines. Effective April 27, 2017, maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $209,002 per day, with a maximum of $2,090,022 for a series of violations. In June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural

gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of natural gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as further amended by the 2016 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require ETP to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in ETP incurring increased operating costs that could be significant and have a material adverse effect on ETP’s results of operations or financial condition.
ETP’s business involves the generation, handling and disposal of hazardous substances, hydrocarbons and wastes, which activities are subject to environmental and worker health and safety laws and regulations that may cause ETP to incur significant costs and liabilities.
ETP’s business is subject to stringent federal, tribal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit, or prevent emissions, discharges or releases of various materials from ETP’s pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from ETP’s construction and operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective obligations, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property and natural resource damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or wastes into the environment.
ETP may incur substantial environmental costs and liabilities because of the underlying risk arising out of its operations. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation costs, liabilities or natural resource damages that could substantially increase our costs for site remediation projects. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.
Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on ETP’s operations or financial position. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to ETP’s customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new emission controls on some of ETP’s equipment, result in longer permitting timelines or new restrictions or prohibitions with respect to permits or projects, and significantly increase its capital expenditures and operating costs, which could adversely impact its business. Historically, ETP has been able to satisfy the more stringent nitrogen oxide emission reduction requirements that affect its compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that it will not incur material costs in the future to meet the new, more stringent ozone standard.
Product liability claims and litigation could adversely affect our subsidiaries business and results of operations.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.

Along with other refiners, manufacturers and sellers of gasoline, Sunoco, Inc. is a defendant in numerous lawsuits that allege methyl tertiary butyl ether (“MTBE”) contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to Sunoco, Inc. An adverse determination of liability related to these allegations or other product liability claims against Sunoco, Inc. could have a material adverse effect on our business or results of operations.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the services we provide.
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted rules under authority of the Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting "best available control technology" standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, the Subpart OOOOa standards have been subject to attempts by the EPA to stay portions of those standards, and the agency proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule and, as a result, the June 2016 rule remains in effect but future implementation of the 2016 standards is uncertain at this time. This rule, should it remain in effect, and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to ETP’s operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect ETP’s business. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France preparing an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but rather includes pledges to voluntarily limit or reduce future emissions. In August 2017, the United States State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on ETP’s business, financial condition, demand for its services, results of operations, and cash flows. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded

that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on ETP’s assets.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative instruments to mitigate the risks of changes in commodity prices and interest rates and other risks associated with our business.
Provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and rules adopted by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other prudential regulators establish federal regulation of the physical and financial derivatives, including over-the-counter derivatives market and entities, such as us, participating in that market. While most of these regulations are already in effect, the implementation process is still ongoing and the CFTC continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, any new regulations or modifications to existing regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability and/or liquidity of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. Any of these consequences could have a material adverse effect on our financial condition, results of operations and cash available for distribution to our unitholders.
The CFTC has re-proposed speculative position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, although certain bona fide hedging transactions would be exempt from these position limits provided that various conditions are satisfied. The CFTC has also finalized a related aggregation rule that requires market participants to aggregate their positions with certain other persons under common ownership and control, unless an exemption applies, for purposes of determining whether the position limits have been exceeded. If adopted, the revised position limits rule and its finalized companion rule on aggregation may create additional implementation or operational exposure. In addition to the CFTC federal speculative position limit regime, designated contract markets (“DCMs”) also maintain speculative position limit and accountability regimes with respect to contracts listed on their platform as well as aggregation requirements similar to the CFTC’s final aggregation rule. Any speculative position limit regime, whether imposed at the federal-level or at the DCM-level may impose added operating costs to monitor compliance with such position limit levels, addressing accountability level concerns and maintaining appropriate exemptions, if applicable.
The Dodd-Frank Act requires that certain classes of swaps be cleared on a derivatives clearing organization and traded on a DCM or other regulated exchange, unless exempt from such clearing and trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The CFTC and prudential regulators have also adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for and rely upon an end-user exception from such clearing and margin requirements for the swaps we enter into to hedge our commercial risks. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.
A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail ETP’s operations and otherwise materially adversely affect their cash flow.
Some of ETP’s operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas pipeline and other facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Virtually all of ETP’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.
If one or more facilities that are owned by ETP or that deliver natural gas or other products to ETP are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s cash available for paying distributions to its Unitholders, including us.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s financial position and results of operations, as applicable. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
Terrorist attacks aimed at our facilities could adversely affect its business, results of operations, cash flows and financial condition.
The United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on ETP’s or Sunoco LP’s facilities or pipelines, those of their customers, or in some cases, those of other pipelines could have a material adverse effect on ETP’s or Sunoco LP’s business, financial condition and results of operations.
Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill-response plans, and other related restrictions arising after the Deepwater Horizon incident in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.
In recent years, the federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the United States Department of the Interior, have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.
In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural gas exploration and production operations conducted offshore by certain of ETP’s customers. For example, in April 2016, the BOEM published a proposed rule that would update existing air-emissions requirements relating to offshore oil and natural-gas activity on federal Outer Continental Shelf waters. However, in May 2017, Order 3350 was issued by the Department of the Interior Secretary Ryan Zinke, directing the BOEM to reconsider a number of regulatory initiatives governing oil and gas exploration in offshore waters, including, among other things, a cessation of all activities to promulgate the April 2016 proposed rulemaking (“Order 3350”). In an unrelated legal initiative, BOEM issued a Notice to Lessees and Operators (“NTL #2016-N01”) that became effective in September 2016 and imposes more stringent requirements relating to the provision of financial assurance to satisfy decommissioning obligations. Together with a recent re-assessment by BSEE in 2016 in how it determines the amount of financial assurance required, the revised BOEM-administered offshore financial assurance program that is currently being implemented is expected to result in increased amounts of financial assurance being required of operators on the OCS, which amounts may be significant. However, as directed under Order 3350, the BOEM has delayed implementation of NTL #2016-N01 so that it may reconsider this regulatory initiative and, currently, this NTL’s implementation timeline has been extended indefinitely beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The April 2016 proposed rule and NTL #2016-N01, should they be finalized and/or implemented, as well as any new rules, regulations, or legal initiatives could delay or disrupt our customers operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to incur penalties, or shut-in production or lease cancellation. Also, if material spill events were to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities offshore and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development. The overall costs imposed on ETP’s customers to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete. We cannot predict with any certainty the full impact of any new laws or regulations on ETP’s customers’ drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. The occurrence of any one or more of these developments could result in decreased demand for ETP’s services, which could have a material adverse effect on its business as well as its financial position, results of operation and liquidity.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we store and transport.
The petroleum products that we store and transport through ETP’s operations are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
In addition, our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.
Our business could be affected adversely by union disputes and strikes or work stoppages by Panhandle’s and Sunoco LP’s unionized employees.
As of December 31, 2017, approximately 5% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that Panhandle or Sunoco, Inc. will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.
Governmental regulations and policies, particularly in the areas of taxation, energy and the environment, have a significant impact on our retail marketing business.
Federally mandated standards for use of renewable biofuels, such as ethanol and biodiesel in the production of refined products, are transforming traditional gasoline and diesel markets in North America. These regulatory mandates present production and logistical challenges for both the petroleum refining and ethanol industries, and may require us to incur additional capital expenditures or expenses particularly in our retail marketing business. We may have to enter into arrangements with other parties to meet our obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits. There also will be compliance costs related to these regulations. We may experience a decrease in demand for refined petroleum products due to new federal requirements for increased fleet mileage per gallon or due to replacement of refined petroleum products by renewable fuels. In addition, tax incentives and other subsidies making renewable fuels more competitive with refined petroleum products may reduce refined petroleum product margins and the ability of refined petroleum products to compete with renewable fuels. A structural expansion of production capacity for such renewable biofuels could lead to significant increases in the overall production, and available supply, of gasoline and diesel in markets that we supply. In addition, a significant shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel, or otherwise, also could lead to a decrease in demand, and reduced margins, for the refined petroleum products that we market and sell.
It is possible that any, or a combination, of these occurrences could have a material adverse effect on Sunoco, Inc.’s business or results of operations.
Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.
Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.

Cybersecurity breaches and other disruptions could compromise our information and operations, and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers, suppliers and business partners, and personally identifiable information of our employees, in our data centers and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations and business strategy. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties for divulging shipper information, disruption of our operations, damage to our reputation, and loss of confidence in our products and services, which could adversely affect our business.
Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-today operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.
The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results.
Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values, changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership’s future consolidated financial results. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged by the Partnership’s regulated businesses, the Partnership’s subsidiaries may not recover all of the costs and those rates are generally not immediately responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the impact of these benefits on operating results could significantly increase.
Mergers among customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our terminals, or reduced crude oil marketing margins or volumes.
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of our systems in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers and could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations, financial position, or cash flows.
The liquefaction project is dependent upon securing long-term contractual arrangements for the off-take of LNG on terms sufficient to support the financial viability of the project
LCL, an entity whose parent is owned 60% by ETE and 40% by ETP, is in the process of developing a liquefaction project at the site of ETE’s existing regasification facility in Lake Charles, Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc (now "Shell") related to this project expired in February 2017. On June 28, 2017, LCL signed a memorandum of understanding with Korea Gas Corporation and Shell to study the feasibility of a joint development of the Lake Charles liquefaction project. The project would utilize existing dock and storage facilities owned by ETE located on the Lake Charles site. The parties’ determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the off-take of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets (particularly Europe and Asia).  Some of these costs fluctuate based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no assurance that the parties will determine to proceed to develop this project.

The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or revocation.
While LCL has received authorization from the DOE to export LNG to non-FTA countries, the non-FTA authorization is subject to review, and the DOE may impose additional approval and permit requirements in the future or revoke the non-FTA authorization should the DOE conclude that such export authorization is inconsistent with the public interest.  The failure by LCL to timely maintain the approvals necessary to complete and operate the liquefaction project could have a material adverse effect on its operations and financial condition.
Sunoco LP is subject to federal laws related to the Renewable Fuel Standard.
New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make additional capital expenditures or incur additional liabilities. For example, certain independent refiners have initiated discussions with the EPA to change the way the Renewable Fuel Standard (RFS) is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers are obligated to obtain renewable identification numbers (“RINS”) either by blending biofuel into gasoline or through purchase in the open market. If the obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have to utilize the RINS it obtains through its blending activities to satisfy a new obligation and would be unable to sell RINS to other obligated parties, which may cause an impact on the fuel margins associated with Sunoco LP’s sale of gasoline.
The occurrence of any of the events described above could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to its unitholders.
Sunoco LP is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it purchases, stores, transports, and sells to its distribution customers.
Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities, including commodities that Sunoco LP distributes. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products, or other more stringent requirements for fuels, could reduce Sunoco LP’s ability to procure product, require it to incur additional handling costs and/or require the expenditure of capital. If Sunoco LP is unable to procure product or recover these costs through increased selling price, it may not be able to meet its financial obligations. Failure to comply with these regulations could result in substantial penalties for Sunoco LP.
The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements.
Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to stockholders of corporations that are subject to all of the corporate governance requirements of the applicable stock exchange.
Tax Risks to Unitholders
Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the IRS were to treat us, ETP or Sunoco LP as a corporation for federal income tax purposes or if we, ETP or Sunoco LP become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investments in ETP and Sunoco LP depend largely on ETP and Sunoco LP being treated as partnerships for federal income tax purposes. Despite the fact that we, ETP and Sunoco LP are each a limited partnership under Delaware law, we would each be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we, ETP and Sunoco LP satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us, ETP or Sunoco LP to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we, ETP or Sunoco LP were treated as a corporation, we would pay federal income tax at the corporate tax rate and we would likely pay additional state income taxes at varying rates. Distributions to Unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to Unitholders. Because a tax would then be imposed upon us as a corporation, our cash available for distribution to Unitholders would be substantially reduced. Therefore,

treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of our Common Units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our Unitholders. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or to additional taxation as an entity for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing United States federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for United States federal income tax purposes.
In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for United States federal income tax purposes.
However, any modification to the United States federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for United States federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
If the IRS contests the federal income tax positions we take, the market for our Common Units may be adversely affected and the costs of any such contest will reduce cash available for distributions to our Unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the prices at which they trade. In addition, the costs of any contest with the IRS will be borne by us reducing the cash available for distribution to our Unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our Unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each Unitholder and former Unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our Unitholders and former Unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current Unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such Unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our Unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income which will be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.
Tax gain or loss on disposition of our Common Units could be more or less than expected.
If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to our unitholders in excess of the total net taxable income the unitholder was allocated for a unit, which decreased their tax basis in that unit, will, in effect, become taxable income to our unitholders if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to Unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be “unrelated business taxable income” and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.
Non-United States Unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.
Non-United States unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a United States trade or business.  As a result, distributions to a Non-United States unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-United States unitholder who sells or otherwise disposes of a unit will also be subject to United States federal income tax on the gain realized from the sale or disposition of that unit. 
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-United States unitholder’s sale or exchange of an interest in a partnership that is engaged in a United States trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges.  It is not clear if or when such regulations or other guidance will be issued.  Non-United States unitholders should consult a tax advisor before investing in our units.
We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
Even though we (as a partnership for United States federal income tax purposes) are not subject to United States federal income tax, some of our operations are conducted through subsidiaries that are organized as corporations for United States federal income tax purposes. The taxable income, if any, of subsidiaries that are treated as corporations for United States federal income tax purposes, is subject to corporate-level United States federal income taxes, which may reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain positions may be successfully challenged by the IRS, state or local jurisdictions.

We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the Common Units.
Because we cannot match transferors and transferees of Common Units and because of other reasons, we have adopted depreciation, depletion and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units and could have a negative impact on the value of our Common Units or result in audit adjustments to tax returns of our Unitholders. Moreover, because we have subsidiaries that are organized as C corporations for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having a greater tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our Unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method, and if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our Unitholders.
A Unitholder whose units are the subject of a securities loan (e.g. a loan to a “short seller”) to cover a short sale of units may be considered as having disposed of those units. If so, the Unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a Unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the Unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the Unitholder and any cash distributions received by the Unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies in determining Unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.
In addition to federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or our subsidiaries conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. We currently own property or conduct business in many states, most of which impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, Unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, our unitholders are entitled to a deduction for the interest we have paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. Although the interest limitation does not apply to certain regulated pipeline businesses, application of the interest limitation to tiered businesses like ours that hold interests in regulated and unregulated businesses is not clear. Pending further guidance specific to this issue, we have not yet determined the impact the limitation could have on our unitholders’ ability to deduct our interest expense, but it is possible that our unitholders’ interest expense deduction will be limited.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
A description of our properties is included in “Item 1. Business.” In addition, we own office buildings for our executive offices in Dallas, Texas and office buildings in Newton Square, Pennsylvania and Houston, Corpus Christi and San Antonio, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.
We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.
Substantially all of our subsidiaries’ pipelines, which are described in “Item 1. Business,” are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. Our subsidiaries have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our subsidiaries’ pipelines were built were purchased in fee. ETP also owns and operates multiple natural gas and NGL storage facilities and owns or leases other processing, treating and conditioning facilities in connection with its midstream operations.
ITEM 3. LEGAL PROCEEDINGS
Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2017, Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico.

The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland.
Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
In January 2012, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas.  The proposed penalties are in excess of $100,000. The case went to hearing in November 2016 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.
In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In December 2016, we received multiple Notice of Violations (“NOVs”) from the Delaware County Regional Water Quality Control Authority (“DELCORA”) in connection with a discharge at our Marcus Hook Industrial Complex (“MHIC”) in July 2016. We also entered in a Consent Order and Agreement from the Pennsylvania Department of Environmental Protection (“PADEP”) related to our tank inspection plan at MHIC.  These actions propose penalties in excess of $100,000, and we are currently in discussions with the PADEP and DELCORA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows, or financial position.
The Ohio Environmental Protection Agency (“Ohio EPA”) has alleged that various environmental violations have occurred during construction of the Rover pipeline project. The alleged violations include inadvertent returns of drilling muds and fluids at horizontal directional drilling (“HDD”) locations in Ohio that affected waters of the State, storm water control violations, improper disposal of spent drilling mud containing diesel fuel residuals, and open burning. The alleged violations occurred from April 2017 to July 2017. Although Rover has successfully completed clean-up mitigation for the alleged violations to Ohio EPA’s satisfaction, the Ohio EPA has proposed penalties of approximately $2.6 million in connection with the alleged violations and is seeking certain injunctive relief. The Ohio Attorney General filed a complaint in the Court of Common Pleas of Stark County, Ohio to obtain these remedies and that case remains pending and is in the early stages. The timing or outcome of this matter cannot be reasonably

determined at this time; however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
In addition, on May 10, 2017, the FERC prohibited Rover from conducting HDD activities at 27 sites in Ohio. On July 31, 2017, the FERC issued an independent third party assessment of what led to the release at the Tuscarawas River site and what Rover can do to prevent reoccurrence once the HDD suspension is lifted. Rover notified the FERC of its intention to implement the suggestions in the assessment and to implement additional voluntary protocols. In response, FERC authorized Rover to resume HDD activities at certain sites. On January 24, 2018, FERC ordered Rover to cease HDD activities at the Tuscarawas River HDD site pending FERC review of additional information from Rover. Rover continues to correspond with regulators regarding drilling operations and drilling plans at the HDD sites where Rover has not yet completed HDD activities, including the Tuscarawas River HDD site. The timing or outcome of this matter cannot be reasonably determined at this time. We do not expect there to be a material impact to its results of operations, cash flows or financial position.
In late 2016, FERC Enforcement Staff began a non-public investigation of Rover’s demolition of the Stoneman House, a potential historic structure, in connection with Rover’s application for permission to construct a new interstate natural gas pipeline and related facilities.  Rover and ETP are cooperating with the investigation.  In March and April 2017, Enforcement Staff provided Rover its non-public preliminary findings regarding its investigation.  The company disagrees with those findings and intends to vigorously defend against any potential penalty. Given the stage of the proceeding, and the non-public nature of the preliminary findings and investigation, ETP is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.
On July 25, 2017, the Pennsylvania Environmental Hearing Board (“EHB”) issued an order to SPLP to cease HDD activities in Pennsylvania related to the Mariner East 2 project.  The EHB issued the order in response to a complaint filed by environmental groups against SPLP and the Pennsylvania Department of Environmental Protection (“PADEP”).  On August 10, 2017 the parties reached a final settlement requiring that SPLP reevaluate the design parameters of approximately 26 drills on the Mariner East 2 project and approximately 43 drills on the Mariner East 2X project.  The settlement agreement also provides a defined framework for approval by PADEP for these drills to proceed after reevaluation.  Additionally, the settlement agreement requires modifications to several of the HDD plans that are part of the PADEP permits.  Those modifications have been completed and agreed to by the parties and the reevaluation of the drills has been initiated by the company.
In addition, on June 27, 2017 and July 25, 2017, the PADEP entered into a Consent Order and Agreement with SPLP regarding inadvertent returns of drilling fluids at three HDD locations in Pennsylvania related to the Mariner East 2 project.  Those agreements require SPLP to cease HDD activities at those three locations until PADEP reauthorizes such activities and to submit a corrective action plan for agency review and approval.  SPLP is working to fulfill the requirements of those agreements and has been authorized by PADEP to resume drilling at one of the three locations.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
On January 18, 2018, PHMSA issued a NOPV and a Proposed Civil Penalty in connection with alleged violations on ETP’s East Boston jet fuel pipeline in Boston, MA. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
On January 18, PHMSA issued a NOPV and a PCO in connection with alleged violations on Eastern Area refined products and crude oil pipeline system in the States of MI, OH, PA, NY, NJ and DE. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed above were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report environmental governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $100,000.
For a description of other legal proceedings, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

PART II
ITEM 5.  MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Parent Company
Market Price of and Distributions on Common Units and Related Unitholder Matters
The Parent Company’s common units are listed on the NYSE under the symbol “ETE.” The following table sets forth, for the periods indicated, the high and low sales prices per ETE Common Unit, as reported on the NYSE Composite Tape, and the amount of cash distributions paid per ETE Common Unit for the periods indicated.
 Price Range 
Cash
Distribution (1)
 High Low 
Fiscal Year 2017:     
Fourth Quarter$18.71
 $15.64
 $0.3050
Third Quarter18.50
 16.18
 0.2950
Second Quarter19.82
 15.03
 0.2850
First Quarter20.05
 17.62
 0.2850
      
Fiscal Year 2016:     
Fourth Quarter$19.99
 $13.77
 $0.2850
Third Quarter19.44
 13.45
 0.2850
Second Quarter15.13
 6.40
 0.2850
First Quarter14.39
 4.00
 0.2850

(1)
Distributions are shown in the quarter with respect to which they relate. Please see “Cash Distribution Policy” below for a discussion of our policy regarding the payment of distributions.
Description of Units
As of February 16, 2018, there were approximately 158,922 individual common unitholders, which includes common units held in street name. Common units represent limited partner interest in us that entitle the holders to the rights and privileges specified in the Parent Company’s Third Amended and Restated Agreement of Limited Partnership, as amended to date (the “Partnership Agreement”).
As of December 31, 2017, limited partners own an aggregate 94.4% limited partner interest in us. Our General Partner owns an aggregate 0.2% General Partner interest in us. Our common units are registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and are listed for trading on the NYSE. Each holder of a common unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all common units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The common units are entitled to distributions of Available Cash as described below under “Cash Distribution Policy.”
On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on

a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.
The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 2017.
Cash Distribution Policy
General.  The Parent Company will distribute all of its “Available Cash” to its unitholders and its General Partner within 50 days following the end of each fiscal quarter.
Definition of Available Cash.Available Cash is defined in the Parent Company’s Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:
provide for the proper conduct of its business;
comply with applicable law and/or debt instrument or other agreement; and
provide funds for distributions to unitholders and its General Partner in respect of any one or more of the next four quarters.
Recent Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.
Securities Authorized for Issuance Under Equity Compensation Plans
For information on the securities authorized for issuance under ETE’s equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”
ITEM 6.  SELECTED FINANCIAL DATA
The selected historical financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and accompanying notes thereto included elsewhere in this report. The amounts in the table below, except per unit data, are in millions.
As discussed in Note 2 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data,” in the fourth quarter of 2017, ETP changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories were changed from last-in, first-out (“LIFO”) method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

 Years Ended December 31,
 2017 2016* 2015* 2014* 2013*
Statement of Operations Data:         
Total revenues$40,523
 $31,792
 $36,096
 $54,435
 $48,335
Operating income2,713
 1,843
 2,287
 2,389
 1,587
Income from continuing operations2,543
 462
 1,023
 1,014
 318
Income (loss) from discontinued operations(177) (462) 38
 60
 33
Net Income2,366
 —
 1,061
 1,010
 351
Basic income from continuing operations per limited partner unit0.86
 0.95
 1.11
 0.57
 0.17
Diluted income from continuing operations per limited partner unit0.84
 0.93
 1.11
 0.57
 0.17
Basic income (loss) from discontinued operations per limited partner unit(0.01) (0.01) —
 0.01
 0.01
Diluted income (loss) from discontinued operations per limited partner unit(0.01) (0.01) —
 0.01
 0.01
Cash distribution per common unit1.17
 1.14
 1.08
 0.80
 0.67
Balance Sheet Data (at period end):         
Assets held for sale3,313
 3,588
 3,681
 3,372
 —
Total assets(1)
86,246
 78,925
 71,144
 64,266
 50,367
Liabilities associated with assets held for sale75
 48
 42
 47
 —
Long-term debt, less current maturities43,671
 42,608
 36,837
 29,477
 22,562
Total equity29,980
 22,431
 23,553
 22,301
 16,341
*As adjusted for the change in accounting policy related to inventory valuation, as discussed above.
(1)
Includes assets held for sale
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts, except per unit data, are in millions)
Energy Transfer Equity, L.P. is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ETE.” ETE was formed in September 2002 and completed its initial public offering in February 2006.
The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
OVERVIEW
Energy Transfer Equity, L.P. directly and indirectly owns equity interests in ETP and Sunoco LP, both publicly traded master limited partnerships engaged in diversified energy-related services.
The historical common units for ETP presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger, discussed in “Item 1. Business.”
At January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and the Partnership’s ownership of Lake Charles LNG. The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses, debt service requirements and at ETE’s election, capital contributions to ETP and Sunoco LP in respect of ETE’s general partner interests in ETP and Sunoco LP. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries.
In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.
General
Our primary objective is to increase the level of our distributable cash flow to our unitholders over time by pursuing a business strategy that is currently focused on growing our subsidiaries’ natural gas and liquids businesses through, among other things, pursuing certain construction and expansion opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.
Our reportable segments are as follows:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
Each of the respective general partners of ETP and Sunoco LP have separate operating management and boards of directors. We control ETP and Sunoco LP through our ownership of their respective general partners.
Recent Developments
ETE Senior Notes Offering
In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under ETE’s term loan facility and for general partnership purposes.
Sunoco LP Series A Preferred Units
On March 30, 2017, the Partnership purchased 12 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units was 10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate would become a floating rate of 8.00% plus three-month LIBOR of the Liquidation Preference.
In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.
ETE January 2017 Private Placement and ETP Unit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units.
January 2018 Sunoco LP Common Units Repurchase
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.

CDM Contribution Agreement
In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.
In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million.
ETP Credit Facilities
On December 1, 2017 ETP entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).
ETP Series A and Series B Preferred Units
In November 2017, ETP issued 950,000 of its 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units at a price of $1,000 per unit.
Distributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
ETP Senior Notes Offering
In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility and for general partnership purposes.
ETP August 2017 Units Offering
In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.

Rover Contribution Agreement
In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.
ETP and Sunoco Logistics Merger
In April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed a merger transaction (the “Sunoco Logistics Merger”) in which Sunoco Logistics acquired Energy Transfer Partners, L.P. in a unit-for-unit transaction, with the Energy Transfer Partners, L.P. unitholders receiving 1.5 common units of Sunoco Logistics for each Energy Transfer Partners, L.P. common unit they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE.
Sunoco LP Private Offering of Senior Notes
On January 23, 2018, Sunoco LP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.875% senior notes due 2023, $800 million in aggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing of the asset purchase agreement with 7-Eleven to: 1) redeem in full its existing senior notes as of December 31, 2017, comprised of $800 million in aggregate principal amount of 6.250% senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; 2) repay in full and terminate the Sunoco LP Term Loan; 3) pay all closing costs and taxes in connection with the 7-Eleven transaction; 4) redeem the outstanding Sunoco LP Series A Preferred Units as mentioned above; and 5) repurchase 17,286,859 common units owned by ETP as mentioned above.
Sunoco LP Convenience Store Sale
On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven (“SEI Fuel” and together with 7-Eleven, referred to herein collectively as “Buyers”). Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.3 billion.
Sunoco LP has signed definitive agreements with a commission agent to operate the approximately 207 retail sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the previously announced transaction with 7-Eleven, Inc. Conversion of these sites to the commission agent is expected to occur in the first quarter of 2018.
Sunoco LP Real Estate Sale
On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.
Permian Express Partners
In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois

terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
Results of Operations
We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.
Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section below titled “Segment Operating Results.” Total Segment Adjusted EBITDA, as presented below, is equal to the consolidated measure of Adjusted EBITDA, which is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures. Our definition of total or consolidated Adjusted EBITDA is consistent with the definition of Segment Adjusted EBITDA above.
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.
As discussed in Note 1 to the consolidated financial statements in “Item 8. Financial Statements and Supplementary Data,” the merger of legacy ETP and legacy Sunoco Logistics in April 2017 resulted in legacy ETP being treated as the surviving entity from an accounting perspective. Accordingly, the financial data below related to our Investment in ETP reflects the consolidated financial information of legacy ETP.
As discussed in Note 2 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data,” in the fourth quarter of 2017, ETP changed its accounting policy related to certain inventories. Certain crude oil, refined product and NGL inventories were changed from last-in, first-out (“LIFO”) method to the weighted average cost method. These changes have been applied retrospectively to all periods presented, and the prior period amounts reflected below have been adjusted from those amounts previously reported.

Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Consolidated Results
 Years Ended December 31,  
 2017 2016* Change
Segment Adjusted EBITDA:     
Investment in ETP$6,712
 $5,733
 $979
Investment in Sunoco LP732
 665
 67
Investment in Lake Charles LNG175
 179
 (4)
Corporate and other(31) (170) 139
Adjustments and eliminations(268) (272) 4
Total7,320
 6,135
 1,185
Depreciation, depletion and amortization(2,554) (2,216) (338)
Interest expense, net of interest capitalized(1,922) (1,804) (118)
Gains on acquisitions—
 83
 (83)
Impairment losses(1,039) (1,040) 1
Losses on interest rate derivatives(37) (12) (25)
Non-cash unit-based compensation expense(99) (70) (29)
Unrealized gains (losses) on commodity risk management activities59
 (136) 195
Inventory valuation adjustments24
 97
 (73)
Losses on extinguishments of debt(89) —
 (89)
Impairment of investments in unconsolidated affiliates(313) (308) (5)
Equity in earnings of unconsolidated affiliates144
 270
 (126)
Adjusted EBITDA related to unconsolidated affiliates(716) (675) (41)
Adjusted EBITDA related to discontinued operations(223) (199) (24)
Other, net155
 79
 76
Income from continuing operations before income tax benefit710
 204
 506
Income tax benefit from continuing operations(1,833) (258) (1,575)
Income from continuing operations2,543
 462
 2,081
Income (loss) from discontinued operations, net of income taxes(177) (462) 285
Net income$2,366
 $—
 $2,366
* As adjusted.
See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Results section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily due to additional depreciation and amortization from assets recently placed in service.
Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:
an increase of $48 million of expense recognized by Sunoco LP primarily due to increased term loan borrowings and the issuance of senior notes;
an increase of $48 million of expense recognized by ETP primarily due to recent debt issuances by ETP and its consolidated subsidiaries; and
an increase of $20 million of expense recognized by the Parent Company primarily due to increased borrowings.
Gains on acquisitions. The Partnership recorded gains of $83 million in connection with recent acquisitions during 2016, including $41 million related to Sunoco Logistics’ acquisition of the remaining interest in SunVit.

Impairment Losses. In 2017, ETP recorded goodwill impairments of $262 million related to its interstate transportation and storage operations, $79 million related to its NGL and refined products operations and $452 million related to its other operations. In 2016, ETP recorded goodwill impairments of $638 million related to its interstate transportation and storage operations and $32 million related to its midstream operations. These goodwill impairments were primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve.
In 2017, Sunoco LP recognized goodwill impairment of $387 million, of which $102 million was allocated to continuing operations. In 2016, Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations. These goodwill impairments were due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
In addition, impairment losses also include $127 million and $133 million impairments to property, plant and equipment in ETP’s interstate transportation and storage operations in 2017 and 2016, respectively, due to decreases in projected future cash flows as well as a $10 million impairment to property, plant and equipment in ETP’s midstream operations in 2016.
Losses on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the year ended December 31, 2017 and 2016 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.
Unrealized Gains (Losses) on Commodity Risk Management Activities. See discussion of the unrealized gains (losses) on commodity risk management activities included in the discussion of segment results below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP and ETP’s NGL and refined products and transportation services operations as a result of commodity price changes between periods.
Impairment of Investments in Unconsolidated Affiliates. During the year ended December 31, 2017, ETP recorded impairments to its investments in FEP of $141 million and HPC of $172 million. During the year ended December 31, 2016, ETP recorded an impairment to its investment in MEP of $308 million. Additional discussion on these impairments is included in “Estimates and Critical Accounting Policies” below.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.
Other, net. Other, net in 2017 and 2016 primarily includes amortization of regulatory assets and other income and expense amounts.
Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefit of $1.81 billion in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

Segment Operating Results
In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment Margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment Margin is similar to the GAAP measure of gross margin, except that Segment Margin excludes charges for depreciation, depletion and amortization.
Following is a reconciliation of Segment Margin to operating income, as reported in the Partnership’s consolidated statements of operations:
 Years Ended December 31,
 2017 2016
Investment in ETP$8,253
 $6,747
Investment in Sunoco LP1,108
 1,156
Investment in Lake Charles LNG197
 197
Adjustments and eliminations(1) (1)
Total segment margin9,557
 8,099
    
Less:   
Operating expenses2,644
 2,307
Depreciation, depletion and amortization2,554
 2,216
Selling, general and administrative607
 693
Impairment losses1,039
 1,040
Operating income$2,713
 $1,843
Investment in ETP
 Years Ended December 31,  
 2017
2016 Change
Revenues$29,054
 $21,827
 $7,227
Cost of products sold20,801
 15,080
 5,721
Segment margin8,253
 6,747
 1,506
Unrealized (gains) losses on commodity risk management activities(56) 131
 (187)
Operating expenses, excluding non-cash compensation expense(2,103) (1,841) (262)
Selling, general and administrative expenses, excluding non-cash compensation expense(392) (351) (41)
Adjusted EBITDA related to unconsolidated affiliates984
 946
 38
Other, net26
 101
 (75)
Segment Adjusted EBITDA$6,712
 $5,733
 $979
Segment Adjusted EBITDA. For the year ended December 31, 2017 compared to the prior year, Segment Adjusted EBITDA related to the Investment in ETP increased primarily as a result of the following:
an increase of $13 million in ETP’s intrastate transportation and storage operations resulting from an increase of $74 million due to higher realized gains from pipeline optimization activity and an increase of $10 million in retained fuel sales. These increases were offset by a $57 million decrease in transportation fees due to renegotiated contracts and an $11 million decrease in storage margin;
an increase of $348 million in ETP’s midstream operations primarily due to a $210 million increase in non-fee based margins (excluding changes in unrealized gains and losses) due to higher realized crude oil and NGL prices and volume increases and a $144 million increase in fee-based revenues due to minimum volume commitments in South Texas, increased volumes in

the Permian and Northeast regions, and recent acquisitions, including PennTex; these increases in gross margin were partially offset by increases in operating expenses of $17 million due to recent acquisitions, including PennTex.
an increase of $145 million in ETP’s NGL and refined products transportation and services operations due to an increase in transportation margin of $124 million, primarily due to higher volumes on Texas NGL pipelines and the ramp-up of volumes on the Mariner East system; an increase in fractionation and refinery services margin of $84 million, primarily due to higher NGL volumes from most major producing regions; and an increase in terminal services margin of $29 million due to a $43 million increase from higher throughput volumes on the Marcus Hook and Nederland NGL terminals offset by lower refined products terminal throughput and the sale of one of ETP’s refined product terminals in April 2017; partially offset by a decrease of $54 million in marketing margin (excluding changes in unrealized gains of $95 million) primarily due to the timing of the recognition of margin from optimization activities; an increase of $37 million in operating expenses primarily due to increased utilities costs associated with ETP’s fourth fractionator at Mont Belvieu and the Mariner project ramp up at the Marcus Hook Industrial Complex and an increase in general and administrative expenses of $8 million due to higher allocations; and
an increase of $545 million in ETP’s crude oil transportation and services operations due to an increase of $724 million resulting primarily from placing ETP’s Bakken Pipeline in service in the second quarter of 2017, as well as the acquisition of a crude oil gathering system in West Texas; an increase of $90 million from existing assets due to increased volumes throughout the system; and an increase of $16 million from increased throughput fees, and tank rentals, primarily from increased activity at ETP’s Nederland, Texas crude terminal; partially offset by an increase in operating expenses as a result of placing new projects in service and costs associated with increased volumes on the system; partially offset by a decrease of $78 million in margin from ETP’s crude oil acquisition and marketing business resulting from less favorable market price spreads particularly in the first three quarters of 2017; an increase of $183 million in operating expenses primarily due to placing the Bakken Pipeline in service; and an increase of $24 million in selling, general and administrative expenses primarily due to merger fees and legal and environmental reserves; partially offset by
a decrease of $19 million in ETP’s interstate transportation and storage operations primarily due to a decrease in reservation revenues of $45 million on the Panhandle, Trunkline, and Transwestern pipelines, a decrease of $17 million in gas parking service related revenues on the Panhandle and Trunkline pipelines primarily due to lack of customer demand resulting from weak spreads, a decrease of $19 million in revenues on the Tiger pipeline due to contract restructuring, and a decrease of $5 million on the Sea Robin pipeline due to producer maintenance and production declines. These decreases were partially offset by $55 million of incremental revenues from the placement in partial service of the Rover pipeline effective August 31, 2017, a $6 million dollar decrease in operating expenses and $4 million increase in adjusted EBITDA from unconsolidated affiliates; and
a decrease of $53 million in ETP’s all other operations due to a decrease of $90 million related to the termination of management fees paid by ETE that ended in 2016; a decrease of $31 million from the mark-to-market of physical system gas and settled derivative; and an increase of $17 million in transaction related expenses; partially offset by an increase of $33 million in Adjusted EBITDA related to ETP’s investment in PES; a one-time fee of $15 million received from a joint venture affiliate; an increase of $20 million in crude and power trading activates, primarily from the liquidation of crude inventories; and a decrease of $11 million in expenses related to ETP’s compression business.
Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the years ended December 31, 2017 and 2016 consisted of the following:
 Years Ended December 31,  
 2017 2016 Change
Citrus$336
 $329
 $7
FEP74
 75
 (1)
MEP88
 90
 (2)
HPC46
 61
 (15)
Sunoco LP268
 271
 (3)
Other172
 120
 52
Total Adjusted EBITDA related to unconsolidated affiliates$984
 $946
 $38

These amounts represent ETP’s proportionate share of the Adjusted EBITDA of its unconsolidated affiliates and are based on ETP’s equity in earnings or losses of its unconsolidated affiliates adjusted for its proportionate share of the unconsolidated affiliates’ interest, depreciation, amortization, non-cash items and taxes.
Investment in Sunoco LP
 Years Ended December 31,  
 2017 2016 Change
Revenues$11,723
 $9,986
 $1,737
Cost of products sold10,615
 8,830
 1,785
Segment margin1,108
 1,156
 (48)
Unrealized (gains) losses on commodity risk management activities(3) 5
 (8)
Operating expenses, excluding non-cash compensation expense(456) (455) (1)
Selling, general and administrative, excluding non-cash compensation expense(116) (142) 26
Inventory fair value adjustments(24) (98) 74
Adjusted EBITDA from discontinued operations223
 199
 24
Segment Adjusted EBITDA$732
 $665
 $67
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include MACS, Sunoco, LLC, Susser and Sunoco Retail LLC beginning September 1, 2014. MACS, Sunoco, LLC, Susser and Sunoco Retail LLC were also consolidated by ETP until October 2014, April 2015, July 2015 and March 2016, respectively; therefore, the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the respective periods in 2014 and 2015. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.
Segment Adjusted EBITDA. For the year ended December 31, 2017 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP increased primarily as a result of the following:
an increase of $18 million in gross margin (excluding a $74 million change in fair value adjustments related to inventory and unrealized gains and losses on commodity risk management activities) primarily caused by an increase in wholesale motor fuel gross profit per gallon, partially offset by a net increase in other gross profit consisting of merchandise, rental & other and retail motor fuel of $13 million;
a decrease of $26 million in general and administrative expenses primarily due to higher costs in 2016 related to relocation, employee termination, and higher contract labor and professional fees as the Partnership transitioned offices in Philadelphia, Pennsylvania, Houston, Texas, and Corpus Christi, Texas to Dallas during 2016; and
an increase of $24 million related to discontinued operations; offset by
an increase of $1 million in other operating expenses primarily attributable to Sunoco LP’s retail business which has expanded through third-party acquisitions as well as through the construction of new-to-industry sites.

Investment in Lake Charles LNG
 Years Ended December 31,  
 2013 2012 Change
Revenues$216
 $166
 $50
Operating expenses, excluding non-cash compensation expense(20) (12) (8)
Selling, general and administrative, excluding non-cash compensation expense(9) (19) 10
Segment Adjusted EBITDA$187
 $135
 $52
Amounts reflected above include the results of Lake Charles LNG beginning March 26, 2012, the date which ETE obtained control of Trunkline LNG through the acquistion of Southern Union.
 Years Ended December 31,  
 2017 2016 Change
Revenues$197
 $197
 $—
Operating expenses, excluding non-cash compensation expense(19) (16) (3)
Selling, general and administrative, excluding non-cash compensation expense(3) (2) (1)
Segment Adjusted EBITDA$175
 $179
 $(4)
Lake Charles LNG derives all of its revenue from a contract with a non-affiliated gas marketer.
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Consolidated Results
 Years Ended December 31,  
 2016* 2015* Change
Segment Adjusted EBITDA:     
Investment in ETP$5,733
 $5,517
 $216
Investment in Sunoco LP665
 719
 (54)
Investment in Lake Charles LNG179
 196
 (17)
Corporate and other(170) (104) (66)
Adjustments and eliminations(272) (590) 318
Total6,135
 5,738
 397
Depreciation, depletion and amortization(2,216) (1,951) (265)
Interest expense, net of interest capitalized(1,804) (1,622) (182)
Gain on acquisitions83
 —
 83
Impairment losses(1,040) (339) (701)
Losses on interest rate derivatives(12) (18) 6
Non-cash compensation expense(70) (91) 21
Unrealized losses on commodity risk management activities(136) (65) (71)
Inventory valuation adjustments97
 (67) 164
Losses on extinguishments of debt—
 (43) 43
Impairment of investment in unconsolidated affiliate(308) —
 (308)
Equity in earnings of unconsolidated affiliates270
 276
 (6)
Adjusted EBITDA related to unconsolidated affiliates(675) (713) 38
Adjusted EBITDA related to discontinued operations(199) (228) 29
Other, net79
 23
 56
Income from continuing operations before income tax expense204
 900
 (696)
Income tax expense (benefit) from continuing operations(258) (123) (135)
Income from continuing operations462
 1,023
 (561)
Income (loss) from discontinued operations, net of income taxes(462) 38
 (500)
Net income$—
 $1,061
 $(1,061)
* As adjusted.
See the detailed discussion of Segment Adjusted EBITDA in the Segment Operating Expenses, Excluding Non-Cash Compensation Expense.Results section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased primarily due to additional depreciation and amortization from assets recently placed in service.

Interest Expense, Net of Interest Capitalized. Interest expense increased primarily due to the following:
an increase of $94 million of expense recognized by Sunoco LP primarily due to increased term loan borrowings, the issuance of senior notes and an increase in borrowings under the Sunoco LP revolving credit facility;
an increase of $33 million of expense recognized by the Parent Company primarily related to the May 2015 issuance of $1 billion aggregate principal amount of its 5.5% senior notes; and
an increase of $53 million of expense recognized by ETP (excluding interest expense related to Sunoco LP for the period prior to ETP’s deconsolidation of Sunoco LP on July 1, 2015) primarily due to recent debt issuances by ETP and its consolidated subsidiaries.
Gains on acquisitions. The Partnership recorded gains of $83 million in connection with recent acquisitions during 2016, including $41 million related to Sunoco Logistics’ acquisition of the remaining interest in SunVit.
Impairment Losses. In 2016, ETP recorded goodwill impairments of $638 million related to its interstate transportation and storage operations and $32 million related to its midstream operations. These goodwill impairments were primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations, primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. In addition, impairment losses for 2016 also include a $133 million impairment to property, plant and equipment in ETP’s interstate transportation and storage operations due to a decrease in projected future cash flows as well as a $10 million impairment to property, plant and equipment in ETP’s midstream operations. In 2015, ETP recorded impairments of (i) $99 million related to Transwestern due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, (ii) $106 million related to Lone Star Refinery Services due primarily to changes in assumptions related to potential future revenues as well as the market declines in current and expected future commodity prices, (iii) $110 million of fixed asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of low utilization and expected decrease in future cash flows, and (iv) $24 million of intangible asset impairments related to Lone Star NGL Refinery Services primarily due to the economic obsolescence identified as a result of expected decrease in future cash flows.
Losses on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are recorded in earnings each period. Losses on interest rate derivatives during the year ended December 31, 2016 and 2015 resulted from decreases in forward interest rates, which caused our forward-starting swaps to decrease in value.
Unrealized Losses on Commodity Risk Management Activities. See discussion of the unrealized gains (losses) on commodity risk management activities included in the discussion of segment results below.
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP and ETP’s NGL and refined products and transportation services operations as a result of commodity price changes between periods.
Impairment of Investment in Unconsolidated Affiliate. In 2016, the Partnership impaired its investment in MEP and recorded a non-cash impairment loss of $308 million based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental Information on Unconsolidated Affiliates” and “Segment Operation Results” below.
Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that is classified as held for sale.
Other, net. Other, net in 2016 and 2015 primarily includes amortization of regulatory assets and other income and expense amounts.
Income Tax Benefit. For the years ended December 31, 2016 and 2015, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries. The year ended December 31, 2015 also reflected a benefit of $24 million of net state tax benefit attributable to statutory state rate changes resulting from the Regency Merger and sale of Susser to Sunoco LP, as well as a favorable impact of $11 million due to a reduction in the statutory Texas franchise tax rate which was enacted by the Texas legislature during the second quarter of 2015.

Segment Operating Results
Following is a reconciliation of Segment Margin to operating income, as reported in the Partnership’s consolidated statements of operations:
 Years Ended December 31,
 2016 2015
Investment in ETP$6,747
 $7,578
Investment in Sunoco LP1,156
 980
Investment in Lake Charles LNG197
 216
Adjustments and eliminations(1) (1,346)
Total segment margin8,099
 7,428
    
Less:   
Operating expenses2,307
 2,303
Depreciation, depletion and amortization2,216
 1,951
Selling, general and administrative693
 548
Impairment losses1,040
 339
Operating income$1,843
 $2,287
Investment in ETP
 Years Ended December 31,  
 2016 2015 Change
Revenues$21,827
 $34,292
 $(12,465)
Cost of products sold15,080
 26,714
 (11,634)
Segment margin6,747
 7,578
 (831)
Unrealized losses on commodity risk management activities131
 65
 66
Operating expenses, excluding non-cash compensation expense(1,841) (2,621) 780
Selling, general and administrative expenses, excluding non-cash compensation expense(351) (482) 131
Inventory valuation adjustments—
 (58) 58
Adjusted EBITDA related to unconsolidated affiliates946
 937
 9
Other, net101
 98
 3
Segment Adjusted EBITDA$5,733
 $5,517
 $216
Segment Adjusted EBITDA. For the year ended December 31, 20132016 compared to the prior year, Lake Charles LNG’s operating expenseSegment Adjusted EBITDA related to the Investment in ETP increased primarily as a result of a full yearthe following:
an increase of $70 million on ETP’s intrastate transportation and storage operations which were consolidated beginningdriven by $34 million in natural gas sales (excluding changes in unrealized losses of $17 million) primarily due to higher realized gains from the buying and selling of gas along ETP’s system and an increase of $37 million in storage margin (excluding net changes in unrealized amounts of $28 million related to fair value inventory adjustments and unrealized gains and losses on March 26, 2012.derivatives);
Selling, Generalan increase of $317 million in ETP’s NGL and Administrative, Excluding Non-Cash Compensation Expense. Therefined products transportation and services operations due to an increase in transportation and terminal margin of $239 million primarily due to the ramp-up of several organic growth projects as well as increased volumes from all producing regions; an increase in fractionation and refinery services margin of $118 million (excluding unrealized gains and losses) primarily due to higher NGL volumes from most major producing regions; an increase in storage margin of $36 million primarily due to increased volumes from ETP’s Mont Belvieu fractionators; partially offset by a decrease in marketing margin of $42 million (excluding net changes in unrealized gains and losses of $50 million) primarily due to lower spreads, the timing of withdrawals, and the timing of the recognition of margin from optimization activities; partially offset by an increase of $33 million in operating expenses comparedprimarily due to increased costs associated with

organic growth projects such as our third fractionator in Mont Belvieu,Texas, Mariner East 1, Mariner South and Allegheny Access; and
an increase of $313 million in ETP’s crude oil transportation and services operations due to an increase of $158 million resulting primarily from placing our Permian Express II pipeline in service in the third quarter of 2015, as well as the acquisition of a crude oil gathering system in West Texas; an increase of $49 million from existing assets due to increased volumes throughout the system; an increase of $31 million from our crude terminals assets, largely related to the prior year wasNederland facility; and an increase of $74 million from our crude oil acquisition and marketing activity; offset by an increase of $5 million in selling, general and administrative expenses; partially offset by
a decrease $38 million in ETP’s interstate transportation and storage operations caused by a $56 million decrease in revenues primarily a resultcaused by contract restructuring on the Tiger pipeline, lower reservation revenues on the Panhandle and Trunkline pipelines, lower sales of $9 millioncapacity in the Phoenix and San Juan areas on the Transwestern pipeline, the transfer of merger-related expenses recorded in 2012.

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Table of Contents

Supplemental Pro Forma Financial Information

The following unaudited pro forma consolidated financial information of ETP has been prepared in accordance with Article 11 of Regulation S-X and reflects the pro forma impactsone of the Propane Transaction,Trunkline pipelines which was repurposed from natural gas service to crude oil service, the expiration of a transportation rate schedule on the Transwestern pipeline, and declines in production and third-party maintenance on the Sea Robin pipeline, partially offset by higher reservation revenues on the Transwestern pipeline and higher parking revenues on the Panhandle and Trunkline pipelines;
a decrease of $104 million in ETP’s midstream operations due to decreases in gathered volumes primarily due to declines in the South Texas, North Texas, and Mid-Continent/Panhandle regions, partially offset by increases in the Permian region and the impact of recent acquisitions, including PennTex; and
a decrease of $308 million due to the transfer and contribution of ETP’s retail marketing assets to Sunoco MergerLP. The consolidated results of Sunoco LP are reflected in the results for ETP’s all other above through June 2015. Effective July 1, 2015, Sunoco LP was deconsolidated, and ETP Holdco Transactionthe results for all other reflect adjusted EBITDA related to unconsolidated affiliates for ETP’s limited partner interests in Sunoco LP. The impact of the deconsolidation of Sunoco LP reduced segment margin, operating expenses and selling, general and administrative expenses; the impact to segment adjusted EBITDA is offset by the incremental adjusted EBITDA related to unconsolidated affiliates from ETP’s equity method investment in Sunoco LP subsequent to the deconsolidation; and
a decrease of $76 million in adjusted EBITDA related to ETP’s investment in PES.
Adjusted EBITDA Related to Unconsolidated Affiliates. ETP’s Adjusted EBITDA related to unconsolidated affiliates for the years ended December 31, 2012, giving effect that each occurred on January 1, 2012. This unaudited pro forma financial information is provided to supplement the discussion2016 and analysis2015 consisted of the historical financial information and should be read in conjunction with such historical financial information. This unaudited pro forma information is for illustrative purposes only and is not necessarily indicativefollowing:
 Years Ended December 31,  
 2016 2015 Change
Citrus$329
 $315
 $14
FEP75
 75
 —
MEP90
 96
 (6)
HPC61
 61
 —
Sunoco, LLC—
 91
 (91)
Sunoco LP271
 137
 134
Other120
 162
 (42)
Total Adjusted EBITDA related to unconsolidated affiliates$946
 $937
 $9
These amounts represent ETP’s proportionate share of the financial results that would have occurred ifAdjusted EBITDA of its unconsolidated affiliates and are based on ETP’s equity in earnings or losses of its unconsolidated affiliates adjusted for its proportionate share of the Sunoco Mergerunconsolidated affiliates’ interest, depreciation, amortization, non-cash items and ETP Holdco Transaction had been consummated on January 1, 2012.taxes.

Investment in Sunoco LP
 Years Ended December 31,  
 2016 2015 Change
Revenues$9,986
 $12,430
 $(2,444)
Cost of products sold8,830
 11,450
 (2,620)
Segment margin1,156
 980
 176
Unrealized losses on commodity risk management activities5
 2
 3
Operating expenses, excluding non-cash compensation expense(455) (451) (4)
Selling, general and administrative, excluding non-cash compensation expense(142) (118) (24)
Inventory fair value adjustments(98) 78
 (176)
Adjusted EBITDA from discontinued operations199
 228
 (29)
Segment Adjusted EBITDA$665
 $719
 $(54)
The following table presentsInvestment in Sunoco LP segment reflects the pro formaresults of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. Sunoco LP obtained control of MACS in October 2014, Sunoco, LLC in April 2015, Susser in July 2015, and Sunoco Retail LLC in March 2016. Because these entities were under common control, Sunoco LP recast its financial informationstatements to retrospectively consolidate each of the entities beginning September 1, 2014. The segment results above are presented on the same basis as Sunoco LP’s standalone financial statements; therefore, the segment results above also include MACS, Sunoco, LLC, Susser and Sunoco Retail LLC beginning September 1, 2014. MACS, Sunoco, LLC, Susser and Sunoco Retail LLC were also consolidated by ETP until October 2014, April 2015, July 2015 and March 2016, respectively; therefore, the results from those entities are reflected in both the Investment in ETP and the Investment in Sunoco LP segments for the respective periods in 2014 and 2015. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC (through December 2015) and a continuing investment in Sunoco LP, the equity in earnings from which are also eliminated in ETE’s consolidated financial statements.
Segment Adjusted EBITDA. For the year ended December 31, 2012:
 ETE Historical 
Propane Transaction(a)
 
Sunoco, Inc. Historical(b)
 
Southern Union Historical(c)
 
ETP Holdco Pro Forma Adjustments(d)
 Pro Forma
REVENUES$16,964
 $(93) $35,258
 $443
 $(12,174) $40,398
COSTS AND EXPENSES:           
Cost of products sold and operating expenses14,204
 (80) 33,142
 302
 (11,193) 36,375
Depreciation, depletion and amortization871
 (4) 168
 49
 76
 1,160
Selling, general and administrative529
 (1) 459
 11
 (119) 879
Impairment charges—
   124
   (22) 102
Total costs and expenses15,604
 (85) 33,893
 362
 (11,258) 38,516
OPERATING INCOME1,360
 (8) 1,365
 81
 (916) 1,882
OTHER INCOME (EXPENSE):           
Interest expense, net of interest capitalized(1,080) (24) (123) (50) 2
 (1,275)
Equity in earnings of affiliates212
 19
 41
 16
 5
 293
Gain on deconsolidation of Propane Business1,057
 (1,057) —
 —
 —
 —
Gain on formation of Philadelphia Energy Solutions—
 —
 1,144
 —
 (1,144) —
Loss on extinguishment of debt(123) 115
 —
 —
 —
 (8)
Losses on interest rate derivatives(19) —
 —
 —
 —
 (19)
Other, net30
 2
 118
 (2) (2) 146
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT)1,437
 (953) 2,545
 45
 (2,055) 1,019
Income tax expense (benefit)54
 —
 956
 12
 (871) 151
INCOME FROM CONTINUING OPERATIONS$1,383
 $(953) $1,589
 $33
 $(1,184) $868
(a) Propane Transaction adjustments reflect2016 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP decreased primarily as a result of the following:
The adjustments reflecta change of $176 million in the deconsolidation of ETP’s propane operations in connection with the Propane Transaction.
The adjustments reflect the pro forma impacts from the consideration received in connection with the Propane Transaction, including ETP’s receipt of AmeriGas common units and ETP’s use of cash proceeds from the transaction to redeem long-term debt.
The 2012 adjustments include the elimination of (i) the gain recognized by ETP in connection with the deconsolidation of the Propane Business and (ii) ETP’s loss on extinguishment of debt recognized in connection with the use of proceeds to redeem of long-term debt.
(b) Sunoco, Inc. historical amounts in 2012 include only the period from January 1, 2012 through September 30, 2012.
(c) Southern Union historical amounts in 2012 include only the period from January 1, 2012 through March 25, 2012.

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(d) Substantially all of the ETP Holdco pro forma adjustments relate to Sunoco, Inc.’s exit from its Northeast refining operations and formation of the PES joint venture, except for the following:
Thefair value adjustment to depreciation, depletion and amortization reflects incremental amounts for estimated fair values recordedinventory resulting from changes in purchase accountingfuels prices during the year ended December 31, 2016;
a decrease of $29 million related to Sunoco and Southern Union.LP’s retail operations that have been classified as discontinued operations;
The adjustment to selling,an increase of $24 million in general and administrative expenses includesprimarily due to $18 million for the eliminationtransition of merger-related costs incurred, because such costs would not haveemployees from Houston, Texas, Corpus Christi, Texas and Philadelphia, Pennsylvania to Dallas, Texas, with the remaining increase due to higher professional fees and other administrative expenses; partially offset by
an increase of $176 million in segment margin primarily caused by an increase in wholesale motor fuel gross profit of $212 million due to a continuing impact28.7%, or $0.55, decrease in the cost per wholesale motor fuel gallon, offset by a decrease in the gross profit on resultsretail motor fuel of operations.$37 million.
The adjustment to interest expense includes incremental amortizationInvestment in Lake Charles LNG
 Years Ended December 31,  
 2016 2015 Change
Revenues$197
 $216
 $(19)
Operating expenses, excluding non-cash compensation expense(16) (17) 1
Selling, general and administrative, excluding non-cash compensation expense(2) (3) 1
Segment Adjusted EBITDA$179
 $196
 $(17)
Lake Charles LNG derives all of fair value adjustments to debt recorded in purchase accounting.its revenue from a contract with a non-affiliated gas marketer.
The adjustment to equity in earnings of affiliates reflects the reversal of amounts related to Citrus recorded in Southern Union’s historical income statements.
The adjustment to income tax expense includes the pro forma impact resulting from the pro forma adjustments to pre-tax income of Sunoco, Inc. and Southern Union.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Parent Company Only
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and RegencySunoco LP and cash flows from the operations of Lake Charles LNG. The amount of cash that ETP and RegencySunoco LP distribute to their respective partners, including the Parent Company, each quarter is based on earnings from their respective business activities and the amount of available cash, as discussed below. In connection with previous transactions, we have relinquished a portion of our incentive distributions to be received from ETP and Regency,Sunoco LP, see additional discussion under “Cash Distributions.”
The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company currently expects to fund its short-term needs for such items with cash flows from its direct and indirect investments in ETP, RegencySunoco LP and Lake Charles LNG. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.
We expectThe Parent Company expects ETP, RegencySunoco LP and Lake Charles LNG and their respective subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and working capital needs; however, the Parent Company may issue debt or equity securities from time to time, as we deemit deems prudent to provide liquidity for new capital projects of ourits subsidiaries or for other partnership purposes.

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ETP
ETP’s ability to satisfy its obligations and pay distributions to its Unitholders will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond the control of ETP’s management.
ETP currently expects capital expenditures in 20152018 to be within the following ranges:
 Growth Maintenance
 Low High Low High
Direct(1):
       
Intrastate transportation and storage$30
 $40
 $30
 $35
Interstate transportation and storage(2)
1,000
 1,100
 125
 130
Midstream550
 650
 10
 15
Liquids transportation and services(2)(3)
2,500
 2,600
 20
 25
Retail marketing(4)
185
 235
 80
 100
All other (including eliminations)20
 25
 10
 20
Total direct capital expenditures4,285
 4,650
 275
 325
Indirect(1):
       
Investment in Sunoco Logistics1,800
 2,200
 70
 90
Investment in Sunoco LP(4)
165
 215
 15
 25
Total indirect capital expenditures1,965
 2,415
 85
 115
Total projected capital expenditures$6,250
 $7,065
 $360
 $440
 Growth Maintenance
 Low High Low High
Intrastate transportation and storage$225
 $250
 $30
 $35
Interstate transportation and storage (1)
450
 500
 115
 120
Midstream750
 800
 120
 130
NGL and refined products transportation and services2,425
 2,475
 65
 75
Crude oil transportation and services (1)
425
 525
 90
 100
All other (including eliminations)75
 100
 60
 65
Total capital expenditures$4,350
 $4,650
 $480
 $525
            Less: Project level non-recourse financing—
 —
 —
 —
Partnership level capital funding$4,350
 $4,650
 $480
 $525
(1) 
Indirect capital expenditures comprise those funded by ETP’s publicly traded subsidiaries; all other capital expenditures are reflected as direct capital expenditures.
(2)
Includes capital expenditures related to ourETP’s proportionate ownership of the Bakken, Rover and RoverBayou Bridge pipeline projects.
(3)
Includes 100% of Lone Star’s capital expenditures. ETP expects to receive capital contributions from Regency related to its 30% share of Lone Star of between $350 million and $400 million.
(4)
ETP’s retail marketing operations include the investment in Sunoco LP, as well as ETP’s wholly-owned retail marketing operations. Capital expenditures by Sunoco LP are reflected as indirect because Sunoco LP is a publicly traded subsidiary.
The assets used in ETP’s natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, ETP does not have any significant financial commitments for maintenance capital expenditures in its businesses. From time to time itETP experiences increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe in a timely, manner, higher steel prices and other factors beyond ETP’sour control. However, ETP includes these factors in its anticipated growth capital expenditures for each year.
ETP generally funds its maintenance capital expenditures and distributions with cash flows from operating activities. ETP generally funds growth capital expenditures with proceeds fromof borrowings under credit facilities, long-term debt, the issuance of additional Common Units or a combination thereof.
As of December 31, 2014,2017, in addition to $639$306 million of cash on hand, ETP had available capacity under its revolving credit facilitiesthe ETP Credit Facilities of $1.81$2.51 billion. Based on ETP’s current estimates, it expects to utilize capacity under the ETP Credit Facility,Facilities, along with cash

from operations, to fund its announced growth capital expenditures and working capital needs through the end of 2015;2018; however, ETP may issue debt or equity securities prior to that time as it deems prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.
Sunoco Logistics’ primary sources of liquidity consist of cash generated from operating activities and borrowings under its $1.50 billion credit facility. At December 31, 2014, Sunoco Logistics had available borrowing capacity of $1.35 billion under its revolving credit facility. Sunoco Logistics’ capital position reflects crude oil and refined products inventories based on historical costs under the last-in, first-out (“LIFO”) method of accounting. Sunoco Logistics periodically supplements its cash flows from operations with proceeds from debt and equity financing activities.LP

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Sunoco LP’s primary sources of liquidity consist of cash generated from operating activities, and borrowings under its $1.25$1.50 billion credit facility.facility and the issuance of additional long-term debt or partnership units as appropriate given market conditions. At December 31, 2014,2017, Sunoco LP had available borrowing capacity of $567$726 million under its revolving credit facility.
Regency
Regency expects its sourcesfacility and $28 million of liquidity to include: cash generated from operations and occasional asset sales; borrowings under the Regency Credit Facility; distributions received from unconsolidated affiliates; debt offerings; and issuance of additional partnership units.cash equivalents on hand.
In 2015, Regency2018, Sunoco LP expects to invest $1.60 billionapproximately $90 million in growth capital expenditures of which $1.00 billion is expected to be invested in organic growth projects in the gathering and processing operations; $400approximately $40 million is expected to be invested in Regency’s portion of growth capital expenditures in its NGL services operations; and $200 million is expected to be invested in growth capital expenditures in its contract services operations. In addition, Regency expects to invest $100 million inon maintenance capital expenditures in 2015, including its proportionate share related to joint ventures.
Regencyexpenditures. Sunoco LP may revise the timing of these expenditures as necessary to adapt to economic conditions. Regency expects to fund its growth capital expenditures with borrowings under its revolving credit facility and a combination of debt and equity issuances.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These factors include regulatory changes, the price of our subsidiaries’ products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions, and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisition of assets, while changes in non-cash unit-based compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when ETP has a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.
Following is a summary of operating activities by period:
Year Ended December 31, 20142017
Cash provided by operating activities in 20142017 was $3.18$4.43 billion and net income was $1.12$2.37 billion. The difference between net income and cash provided by operating activities in 20142017 primarily consisted of net non-cash items totaling $1.99$1.78 billion and changes in operating assets and liabilities of $231$192 million. The non-cash activity in 20142017 consisted primarily of depreciation, depletion and amortization of $1.72$2.55 billion, goodwill impairment losses of$1.35 billion, deferred income tax benefit of $370 million,$1.87 billion, inventory valuation adjustments of $473$24 million, losses on extinguishments of debt of $25$89 million and non-cash compensation expense of $82 million, partially offset by the gain on the sale of AmeriGas common units of $177 million and a deferred income tax benefit of $50$99 million.
Year Ended December 31, 20132016
Cash provided by operating activities in 20132016 was $2.42$3.32 billion and net income was $315$0 million. The difference between net income and cash provided by operating activities in 20132016 primarily consisted of net non-cash items totaling $1.94$2.77 billion and changes in operating assets and liabilities of $149$179 million. The non-cash activity in 2016 consisted primarily of depreciation, depletion and amortization of $1.31$2.22 billion, goodwill impairment losses of $689 million,$1.35 billion, deferred income taxestax benefit of $43$177 million, losses on extinguishmentsinventory valuation adjustments of debt of $162$97 million and non-cash compensation expense of $61$70 million.

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Year Ended December 31, 20122015
Cash provided by operating activities in 20122015 was $1.08$2.98 billion and net income was $1.27$1.06 billion. The difference between net income and cash provided by operating activities in 20122015 primarily consisted of net non-cash items totaling $85 million$2.42 billion and changes in operating assets and liabilities of $551 million.$0.87 billion. The non-cash activity in 2015 consisted primarily of a gain on the deconsolidation of ETP’s propane business of $1.06 billion, which was offset by depreciation, depletion and amortization of $871$1.95 billion, impairment losses of $339 million, deferred income tax expense of $239 million,

inventory valuation adjustments of $67 million, losses on extinguishments of debt of $123$43 million and non-cash compensation expense of $47$91 million.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, and cash contributions to ETP’s and Regency’sour joint ventures. Changes in capital expenditures between periods primarily result from increases or decreases in ETP’s or Regency’s growth capital expenditures to fund their respective construction and expansion projects.
Following is a summary of investing activities by period:
Year Ended December 31, 20142017
Cash used in investing activities in 20142017 of $6.80$5.61 billion was comprised primarily of capital expenditures of $5.34$8.41 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $4.14$5.47 billion for growth capital expenditures and $343$429 million for maintenance capital expenditures during 2014. Regency invested $1.20 billion for growth capital expenditures and $98 million for maintenance capital expenditures during 2014.2017. We paid net cash for acquisitions of $2.37 billion and received $814$303 million, in cash received fromincluding the saleacquisition of AmeriGas common units.a noncontrolling interest.
Year Ended December 31, 20132016
Cash used in investing activities in 20132016 of $2.35$8.98 billion was comprised primarily of capital expenditures of $3.45$7.70 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $2.11$5.44 billion for growth capital expenditures and $343$368 million for maintenance capital expenditures during 2013. Regency invested $948 million for growth capital expenditures and $48 million for maintenance capital expenditures during 2013. These expenditures were partially offset by $1.01 billion and $346 million of cash received from the sale of the MGE and NEG assets and the sale of AmeriGas common units, respectively. In addition, ETP2016. We paid net cash for acquisitions of $405 million for acquisitions.$1.40 billion, including the acquisition of a noncontrolling interest.
Year Ended December 31, 20122015
Cash used in investing activities in 20122015 of $4.20$9.74 billion was comprised primarily of capital expenditures of $3.24$8.99 billion (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs). ETP invested $2.74$7.68 billion for growth capital expenditures and $313$485 million for maintenance capital expenditures during 2012. Regency invested $9452015. We paid net cash for acquisitions of $842 million, for growth capital expenditures and $58 million for maintenance capital during 2012 (including amounts related to SUGS). Cash paid forincluding the acquisition of Southern Union was $2.97 billion and ETP received $1.44 billion in proceeds from the contribution of propane.a noncontrolling interest.
Financing Activities
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund ETP’s and Regency’s acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate.
Following is a summary of financing activities by period:
Year Ended December 31, 20142017
Cash provided by financing activities was $3.88 billion$953 million in 2014.2017. We had a consolidated increase in our debt level of $4.49 billion,$340 million, primarily due to Regency’sthe issuance of Parent Company and subsidiary senior notes, and assumption and debt, and Sunoco Logistics’ issuance of $2.00 billionas well as increases in aggregate principal amount of senior notes in April 2014 and November 2014 (see Note 6 to our consolidated financial statements) and an increase of the Parent Company’s debt of $1.88 billion.revolving credit facilities during 2015. Our subsidiaries also received $3.06$3.24 billion in proceeds from common unit offerings, including $1.38$2.28 billion from the issuance of ETP Common Units $428and $952 million from the issuance of Regencyother subsidiary common units. We paid distributions to partners of $1.01 billion, and our subsidiaries paid $2.96 billion on limited partner interests other than those held by the Parent Company.
Year Ended December 31, 2016
Cash provided by financing activities was $5.93 billion in 2016. We had a consolidated increase in our debt level of $6.71 billion, primarily due to the issuance of Parent Company and subsidiary senior notes, as well as increases in our revolving credit facilities during 2015. Our subsidiaries also received $2.56 billion in proceeds from common unit offerings, including $1.10 billion from the issuance of ETP Common Units and $1.25$1.46 billion from the issuance of other subsidiary common units. We paid distributions to partners of $821 million,$1.02 billion, and our subsidiaries paid $1.91$2.77 billion on limited partner interests other than those held by the Parent Company.
Year Ended December 31, 2015
Cash provided by financing activities was $6.79 billion in 2015. We had a consolidated increase in our debt level of $6.63 billion, primarily due to the issuance of Parent Company and subsidiary senior notes, as well as increases in our revolving credit facilities during 2015. Our subsidiaries also received $3.89 billion in proceeds from common unit offerings, including $1.43 billion from

the issuance of ETP Common Units and $2.46 billion from the issuance of other subsidiary common units. We paid distributions to partners of $1.09 billion, and our subsidiaries paid $2.34 billion on limited partner interests other than those held by the Parent Company. We also paid $1.00$1.06 billion to repurchase common units during the year ended December 31, 2014.2015.

Discontinued Operations
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Year Ended December 31, 2013
Cash providedactivities related to discontinued operations by financing activities was $146 million in 2013. We had a consolidated increase in our debt level of $983 million, primarily due to ETP’s issuance of $1.25 billion and $1.50 billion in aggregate principal amount of senior notes in January 2013 and September 2013, respectively, and Sunoco Logistics’ issuance of $700 million in aggregate principal amount of senior notes in January 2013 (see Note 6 to our consolidated financial statements). Our subsidiaries also received $1.76 billion in proceeds from common unit offerings, which consisted of $1.61 billion from the issuance of ETP Common Units and $149 million from the issuance of Regency Common Units. We paid distributions to partners of $733 million, and our subsidiaries paid $1.43 billion on limited partner interests other than those held by the Parent Company. We also paid $340 million to redeem our Preferred Units.period:
Year Ended December 31, 20122017
Cash provided by financingdiscontinued operations was $93 million for the year ended December 31, 2017 resulting from cash provided by operating activities was $3.36 billionof $136 million, cash used in 2012. We had a consolidated increase in our debt levelinvesting activities of $4.02 billion, which primarily consisted of borrowings to fund our acquisitions of Southern Union and Sunoco, Inc. Our subsidiaries also received $1.10 billion in proceeds from common unit offerings, which consisted of $791 million from the issuance of ETP Common Units and $312 million from the issuance of Regency Common Units. We paid distributions to partners of $666$38 million and $24changes in cash included in current assets held for sale of $5 million.
Year Ended December 31, 2016
Cash used in discontinued operations was $385 million tofor the holdersyear ended December 31, 2016 resulting from cash provided by operating activities of our Preferred Units. In addition, our subsidiaries paid $1.02 billion on limited partner interests other than those$93 million, cash used in investing activities of $483 million and changes in cash included in current assets held for sale of $5 million.
Year Ended December 31, 2015
Cash used in discontinued operations was $283 million for the year ended December 31, 2015 resulting from cash provided by the Parent Company.operating activities of $90 million, cash used in investing activities of $360 million and changes in cash included in current assets held for sale of $13 million.

Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
 December 31,
 2014 2013
Parent Company Indebtedness:   
ETE Senior Notes due October 15, 2020$1,187
 $1,187
ETE Senior Notes due January 15, 20241,150
 450
ETE Senior Secured Term Loan, due December 2, 20191,400
 1,000
ETE Senior Secured Revolving Credit Facility due December 2, 2018940
 171
Subsidiary Indebtedness:   
ETP Senior Notes10,890
 11,182
Panhandle Senior Notes1,085
 1,085
PVR Senior Notes790
 —
Regency Senior Notes4,299
 2,800
Sunoco, Inc. Senior Notes715
 965
Sunoco Logistics Senior Notes3,975
 2,150
Transwestern Senior Notes782
 870
Revolving Credit Facilities:   
ETP $2.5 billion Revolving Credit Facility due October 27, 2019570
 65
Regency $1.5 billion Revolving Credit Facility due November 25, 20191,504
 510
Sunoco Logistics’ subsidiary $35 million Revolving Credit Facility due April 30, 201535
 35
Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018150
 200
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019683
 —
Other Long-Term Debt223
 228
Unamortized premiums and fair value adjustments, net283
 301
Total debt30,661
 23,199
Less: current maturities of long-term debt1,008
 637
Long-term debt, less current maturities$29,653
 $22,562
 December 31,
 2017 2016
Parent Company Indebtedness:   
ETE Senior Notes due October 2020$1,187
 $1,187
ETE Senior Notes due January 20241,150
 1,150
ETE Senior Notes due June 20271,000
 1,000
ETE Senior Notes due March 20231,000
 —
ETE Senior Secured Term Loan due December 2, 2019—
 2,190
ETE Senior Secured Term Loan due February 2, 20241,220
 —
ETE Senior Secured Revolving Credit Facility due December 18, 2018—
 875
ETE Senior Secured Revolving Credit Facility due March 24, 20221,188
 —
Subsidiary Indebtedness:   
ETP Senior Notes27,005
 24,855
Panhandle Senior Notes785
 1,085
Sunoco, Inc. Senior Notes—
 400
Transwestern Senior Notes575
 657
Sunoco LP Senior Notes, Term Loan and lease-related obligations3,556
 3,561
Credit Facilities and Commercial Paper:   
ETP $4.0 billion Revolving Credit Facility due December 20222,292
 —
ETP $1.0 billion 364-Day Credit Facility due November 2018 (1)
50
 —
ETLP $3.75 billion Revolving Credit Facility due November 2019—
 2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020—
 1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017—
 630
Sunoco LP $1.5 billion Revolving Credit Facility due September 2019765
 1,000
Bakken Project $2.50 billion Credit Facility due August 20192,500
 1,100
PennTex $275 million MLP Revolving Credit Facility due December 2019—
 168
Other long-term debt8
 31
Unamortized premiums and fair value adjustments, net50
 101
Deferred debt issuance costs(247) (257)
Total debt44,084
 43,802
Less: current maturities of long-term debt413
 1,194
Long-term debt, less current maturities$43,671
 $42,608
(1)
Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.
The terms of our consolidated indebtedness and our subsidiaries are described in more detail below and in Note 6 to our consolidated financial statements.

Senior Notes and Term Loan
87Energy Transfer Equity, L.P. Senior Notes Offering 
TableIn October 2017, ETE issued $1 billion aggregate principal amount of Contents4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.


ETE Term Loan Facility
The Parent Company hasOn February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “ETE“Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement”), whichAgreement has a scheduled maturity date of DecemberFebruary 2, 2019,2024, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements.
Pursuant to the ETE Term Credit Agreement, the lendersTerm Lenders have provided senior secured financing in an aggregate principal amount of $1.0$2.2 billion (the “ETE Term“Term Loan Facility”). The Parent Company shallis not be required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the PartnershipParent Company is required to repayprepay the term loan in connection with dispositions of (a) incentive distribution rightsIDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics ; or Regency, (b) general partnership interests in Regency or (c) equity interests of any Personperson which owns, directly or indirectly, incentive distribution rightsIDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP, or Regency or general partnership interests in Regency,and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics, in each case, yieldingwith a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.
Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets subject to certain exceptionsincluding (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and permitted liens.(ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The ETE Term Loan Facility initially is not guaranteed by any of the Parent Company’sPartnership’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, plus an applicable margin based on the election of the Parent Company for each interest period.period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.50%2.75% and the applicable margin for base rate loans is 1.50%1.75%.
In April 2014, Proceeds of the Parent Company amendedborrowings under the ETE Term Credit Agreement were used to increaserefinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.
On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.
In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.
Sunoco LP Term Loan
Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $1.4$2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of December 31, 2017, the balance on the term loan was $1.24 billion.
The Parent Company used theSunoco LP term loan was repaid in full and terminated on January 23, 2018.
ETP Senior Notes Offering
In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from this $400the offering were used to redeem all of the $500 million increaseaggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under its revolving credit facilitythe Sunoco Logistics Credit Facility and for general partnership purposes. No other significant changes were made to
Credit Facilities and Commercial Paper
Parent Company Credit Facility
Indebtedness under the termsParent Company Credit Facility is secured by all of the ETE TermParent Company’s and certain of its subsidiaries’ tangible and intangible assets, but is not guaranteed by any of the Parent Company’s subsidiaries.

On March 24, 2017, the Parent Company entered into a Credit Agreement including maturity date and interest rate.
ETE Revolving Credit Facility
The Parent Company has a credit agreement (the “Revolving“Revolver Credit Agreement”), which with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of December 2, 2018, withMarch 24, 2022 and includes an option for the PartnershipParent Company to extend the term, in each case subject to the terms and conditions set forth therein.
Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $600 million$1.50 billion at any one time outstanding, (the “ETE Revolving Credit Facility”), and the Parent Company has the option to request increases in the aggregate commitments provided that the aggregate commitments never exceed $1.0 billion. In February 2014, the Partnership increased the capacity on the ETE Revolving Credit Facilityby up to $800 million. In May 2014, the Parent Company amended its revolving credit facility to increase the capacity to $1.2 billion. In February 2015, the Parent Company amended its revolving credit facility to increase the capacity to $1.5 billion.
$500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150 million sublimit.
Under the Revolver Credit Agreement, the obligations of the Parent CompanyPartnership are secured by a lien on substantially all of the Parent Company’sPartnership’s and certain of its subsidiaries’ tangible and intangible assets. Borrowings under the Revolver Credit Agreement are not guaranteed by any of the Parent Company’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, plus an applicable margin based on the election of the Parent Company for each interest period.period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments.
Subsidiary Indebtedness
Sunoco Logistics Senior Notes Offerings
In April 2014, Sunoco Logistics issued $300 million aggregate principal amount As of 4.25% senior notes due April 2024 and $700 million aggregate principal amount of 5.30% senior notes due April 2044. In November 2014, Sunoco Logistics issued an additional $200 million under the April 2024 senior notes and $800 million aggregate principal amount of 5.35% senior notes due May 2045. Sunoco Logistics’ used the net proceeds from the offering to payDecember 31, 2017, there were $1.19 billion outstanding borrowings under the Sunoco Logistics Credit FacilityParent Company revolver credit facility and the amount available for general partnership purposes.

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Credit Facilitiesfuture borrowings was $312 million.
ETP Credit FacilityFacilities
On December 1, 2017 ETP entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).  The ETP CreditFive-Year Facility allows for borrowings ofcontains an accordion feature, under which the total aggregate commitments may be increased up to $2.5$6.0 billion and expires in October 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of ETP’s current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt.certain conditions. ETP uses the ETP Credit FacilityFacilities to provide temporary financing for its growth projects, as well as for general partnership purposes. In February 2015, ETP amended its revolving credit facility to increase the capacity to $3.75 billion.
ETP usesBorrowings under the ETP Credit Facilities are unsecured and initially guaranteed by Sunoco Logistics Partners Operations L.P.  Borrowings under the ETP Credit Facilities will bear interest at a eurodollar rate or a base rate, at ETP’s option, plus an applicable margin.  In addition, ETP will be required to pay a quarterly commitment fee to each lender equal to the product of the applicable rate and such lender’s applicable percentage of the unused portion of the aggregate commitments under the ETP Credit Facilities.  Concurrent with the closing of the ETP Credit Facilities, ETP repaid the entire amount outstanding and terminated its previously existing $3.75 billion ETLP Credit Facility to provide temporary financing for its growth projects, as well as for general partnership purposes. and $2.50 billion Sunoco Logistics Credit Facility.
ETP typically repays amounts outstanding under the ETP Credit FacilityFacilities with proceeds from common unit offerings or long-term notes offerings. The timing of borrowings depends on ETP’s activities and the cash available to fund those activities. The repayments of amounts outstanding under the ETP Credit FacilityFacilities depend on multiple factors, including market conditions and expectations of future working capital needs, and ultimately are a financing decision made by management. Therefore, the balance outstanding under the ETP Credit FacilityFacilities may vary significantly between periods. ETP does not believe that such fluctuations indicate a significant change in its liquidity position, because itETP expects to continue to be able to repay amounts outstanding under the ETP Credit FacilityFacilities with proceeds from common unit offerings or long-term note offerings.
As of December 31, 2014,2017, the ETP CreditFive-Year Facility had $570 million$2.29 billion outstanding, and theof which $2.01 billion was commercial paper. The amount available for future borrowings was $1.81$1.56 billion after taking into account letters of credit of $121$150 million. The weighted average interest rate on the total amount outstanding as of December 31, 20142017 was 1.66%2.48%.
Regency Revolving Credit Facility
The Regency Credit Facility has aggregate revolving commitments of $2.0 billion, with a $500 million incremental facility. The maturity date of the Regency Credit Facility is November 25, 2019.
The outstanding balance of revolving loans under the Regency Credit Facility bears interest at LIBOR plus a margin or an alternate base rate. The alternate base rate used to calculate interest on base rate loans will be calculated using the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.00%. The applicable margin ranges from 0.625% to 1.50% for base rate loans and 1.625% to 2.50% for Eurodollar loans.
Regency pays (i) a commitment fee ranging between 0.30% and 0.45% per annum for the unused portion of the revolving loan commitments; (ii) a participation fee for each revolving lender participating in letters of credit ranging between 1.625% and 2.50% per annum of the average daily amount of such lender’s letter of credit exposure and; (iii) a fronting fee to the issuing bank of letters of credit equal to 0.20% per annum of the average daily amount of its letter of credit exposure. The Regency Credit Facility allows for investments in its joint ventures.
As of December 31, 2014, Regency2017, the ETP 364-Day Facility had a balance$50 million outstanding, of $1.50 billion underand the Regency Credit Facility in revolving credit loans and approximately $23 million in letters of credit. The total amount available under the Regency Credit Facility, as of December 31, 2014, which is reduced by any letters of credit,for future borrowings was approximately $473$950 million. The weighted average interest rate on the total amount outstanding as of December 31, 20142017 was 2.17%5.00%.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintainsETP maintained a $1.50$2.50 billion unsecured revolving credit facilityagreement (the “Sunoco Logistics Credit Facility”) which matures in November 2018. The Sunoco Logistics. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions.Facilities on December 1, 2017.
The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2014, the Sunoco Logistics Credit Facility had $150 million of outstanding borrowings.
West Texas Gulf Pipe Line Company, a subsidiary of Sunoco Logistics, maintains a $35 million revolving credit facility which expires in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. At December 31, 2014, this credit facility had $35 million of outstanding borrowings.

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Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In September 2014,January 2017, Sunoco LP entered into a $1.25 billionlimited waiver to its revolving credit agreementfacility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest

owed under the revolving credit facility. As of December 31, 2017, the Sunoco LP credit facility had $9 million in standby letters of credit. The amount available for future borrowings on the revolver at December 31, 2017 was $726 million.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Sunoco LP“Bakken Credit Facility”), which expires in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million.. As of December 31, 2014, the Sunoco LP Credit Facility had $683 million2017, $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%.
Covenants Related to Our Credit Agreements
Covenants Related to the Parent Company
The ETE Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants, and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.
The ETE Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:
Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company (as defined) to EBITDA (as defined in the agreements)therein) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 77.0 to 1 during a specified acquisition period following the close of a specified acquisition; and
Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1.
1.
Covenants Related to ETP

The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactionstransactions.
The credit agreement relating to the ETP Credit FacilityFacilities contains covenants that limit (subject to certain exceptions) ETP’sthe Partnership’s and certain of ETP’sthe Partnership’s subsidiaries’ ability to, among other things:
incur indebtedness;
grant liens;
enter into mergers;
dispose of assets;
make certain investments;
make Distributions (as defined in such credit agreement)the ETP Credit Facilities) during certain Defaults (as defined in such credit agreement)the ETP Credit Facilities) and during any Event of Default (as defined in such credit agreement)the ETP Credit Facilities);
engage in business substantially different in nature than the business currently conducted by ETPthe Partnership and its subsidiaries;
engage in transactions with affiliates; and
enter into restrictive agreements.
The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit agreement relatingratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from 0.125% to 0.300%.  The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225%.
The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit FacilityFacilities also containslimit us, on a financial covenant that provides that the Leverage Ratio,rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the ETP Credit Facility, shall not exceed underlying credit agreements, of 5.0 to 1, as of the end of each quarter, with a permitted increase

which can generally be increased to 5.5 to 1 during a Specified Acquisition Period,Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as definedcalculated in accordance with the ETP Credit Facility.credit agreements.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of all or substantially all assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Covenants RelatedFailure to Regency
The Regency senior notes containcomply with the various restrictive and affirmative covenants that limit, among other things, Regency’sof our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability and the ability of certain of its subsidiaries, to:
•to incur additional indebtedness;
•debt and/or our ability to pay distributions on, or repurchase or redeem equity interests;

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•make certain investments;
•incur liens;
•enter into certain types of transactions with affiliates; and
•sell assets, consolidate or merge with or into other companies.
If the Regency senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to these covenants except that the liens covenant will continue to be applicable. ETP has advised Regency that it intends to provide an ETP guarantee with respect to the outstanding Regency senior notes upon the closing of the Regency merger, and it is expected that this will result in the Regency senior notes being upgrade an investment grade rating by both Moody’s and S&P.
The Regency Credit Facility contains the following financial covenants:
Regency’s consolidated EBITDA ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.00 to 1.
Regency’s consolidated EBITDA to consolidated interest expense, as defined in the credit agreement governing the Regency Credit Facility, must be greater than 2.50 to 1.
Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3.25 to 1.
The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:
•incur indebtedness;
•grant liens;
•enter into sale and leaseback transactions;
•make certain investments, loans and advances;
•dissolve or enter into a merger or consolidation;
•enter into asset sales or make acquisitions;
•enter into transactions with affiliates;
prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);
•issue capital stock or create subsidiaries; or
engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.

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In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Sunoco LogisticsBakken Credit Facility
Sunoco Logistics’ $1.50 billion credit facilityThe Bakken Credit Facility contains variousstandard and customary covenants including for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:
prohibition of certain incremental secured indebtedness;
prohibition of certain liens / negative pledge;
limitations on uses of loan proceeds;
limitations on asset sales and purchases;
limitations on permitted business activities;
limitations on mergers and acquisitions;
limitations on investments;
limitations on transactions with affiliates; and
maintenance of commercially reasonable insurance coverage.
A restricted payment covenant is also included in the creationBakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of indebtedness and liens, and other covenants relatednot less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the operation and conductcommercial in-service date of the business of Sunoco LogisticsDakota Access and its subsidiaries. The credit facility also limits Sunoco Logistics, on a rolling four-quarter basis,ETCO Project in order to a maximum total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total consolidated debt, excluding net unamortized fair value adjustments, to consolidated Adjusted EBITDA was 3.7 to 1 at December 31, 2014, as calculated in accordance with the credit agreements.make certain restricted payments thereunder.
The West Texas Gulf Pipeline Company’s $35 million credit facility limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio of 1.00 to 1. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 1.67 to 1 and 0.85 to 1, respectively, at December 31, 2014.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility requiresFacilities contain various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. The Sunoco LP Credit Facilities  require Sunoco LP to maintain a leverage

ratio (as defined therein) of not more than 5.50(a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1. The maximum leverage ratio is1.0, (b) as of March 31, 2018, 6.5 to 1.0, (c) as of June 30, 2018, 6.25 to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (in the case of the quarter ending March 31, 2019 and thereafter, subject to upwards adjustmentincreases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of not more than 6.00 to 1 for a period not to exceed three fiscal quarters in$50 million, as permitted under the event Sunoco LP engages in an acquisition of assets, equity interests, operating lines or divisions by Sunoco LP, a subsidiary, an unrestricted subsidiary or a joint venture for a purchase price of not less than $50 million.Credit Facilities.  Indebtedness under the Sunoco LP Credit FacilityFacilities is secured by a security interest in, among other things, all of the Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Sunoco LP Credit FacilityFacilities will be released.
Compliance with our Covenants
We are required to assess compliance quarterly and were in compliance with all requirements, limitations, and covenants relating to ETE’s and its subsidiaries’ debt agreements as of December 31, 2014.2017.
Each of the agreements referred to above are incorporated herein by reference to our, ETP’s, Sunoco Logistics’ and Regency’sSunoco LP’s reports previously filed with the SEC under the Exchange Act. See “Item 1. Business – SEC Reporting.”
Off-Balance Sheet Arrangements
Contingent Residual Support Agreement – AmeriGas
In order to finance the cash portion of the purchase price of the Propane Business described in Note 6 to our consolidated financial statements, AmeriGas Finance LLC (“Finance Company”), a wholly-owned subsidiary of AmeriGas, issued $550 million in aggregate principal amount of 6.75% senior notes due 2020 and $1.0 billion in aggregate principal amount of 7.00% senior notes due 2022. AmeriGas borrowed $1.5 billion of the proceeds of the senior notes issuance from Finance Company through an intercompany borrowing having maturity dates and repayment terms that mirror those of the senior notes (the “Supported Debt”).
In connection with the closing of the contribution of the Propane Business,its propane operations in January 2012, ETP entered into a Contingent Residual Support Agreement with AmeriGas, Finance Company, AmeriGas Finance Corp. and UGI Corp., pursuant to which ETP will providepreviously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the Supported Debt.remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.
PEPL Holdings Guarantee of CollectionSunoco LP Notes
In connectionRetail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with the SUGS Contribution, Regency issued $600respect to (i) $800 million principal amount of 4.50%6.375% senior notes due 2023( issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portionassignment of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basisSunoco LP’s senior notes, to Southern Union) to Regencyits subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and Regency Energy Finance Corp.issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of theprincipal amounts:
$1.00 billion aggregate principal amount of the Regency Debt through maturity in 2023. In connection with the completion4.875%, senior notes due 2023;
$800 million aggregate principal amount of the Panhandle Merger, in which PEPL Holdings was merged with5.50% senior notes due 2026; and into Panhandle,
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, forETC M-A would have the Regency Debt was assumed by Panhandle.obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.

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Contractual Obligations
The following table summarizes our long-term debt and other contractual obligations as of December 31, 2014:2017:
 Payments Due by Period Payments Due by Period
Contractual Obligations Total 
Less Than 1
Year
 1-3 Years 3-5 Years More Than 5 Years Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years
Long-term debt $30,378
 $1,050
 $1,542
 $7,757
 $20,029
 $44,281
 $1,705
 $9,179
 $8,745
 $24,652
Interest on long-term debt(1)
 17,057
 1,565
 3,008
 2,696
 9,788
 24,908
 2,197
 3,887
 3,081
 15,743
Payments on derivatives 159
 20
 83
 50
 6
 223
 84
 139
 —
 —
Purchase commitments(2)
 14,177
 8,362
 3,168
 1,188
 1,459
 3,605
 3,443
 99
 35
 28
Transportation, natural gas storage and fractionation contracts 89
 26
 43
 20
 —
 25
 19
 6
 —
 —
Operating lease obligations 1,437
 151
 247
 210
 829
 1,069
 113
 196
 154
 606
Distributions and redemption of preferred units of a subsidiary(3)
 96
 3
 7
 7
 79
Other(4)
 347
 177
 77
 57
 36
Total(5)
 $63,740
 $11,354
 $8,175
 $11,985
 $32,226
Other(3)
 185
 32
 56
 45
 52
Total(4)
 $74,296
 $7,593
 $13,562
 $12,060
 $41,081
(1) 
Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2014.2017. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2014.2017. To the extent interest rates change, our contractual obligation for interest payments will change. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for further discussion.
(2) 
We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have long and short-term product purchase obligations for refined product and energy commodities with third-party suppliers. These purchase obligations are entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at the time we take delivery of the volumes. Our estimated future variable price contract payment obligations are based on the December 31, 20142017 market price of the applicable commodity applied to future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the contract. Our estimated future fixed price contract payment obligations are based on the contracted fixed price under each commodity contract. Obligations shown in the table represent estimated payment obligations under these contracts for the periods indicated. Approximately $1.12 billion of total purchase commitments relate to production from PES.
(3)
Assumes the outstanding Regency Preferred Units are redeemed for cash on September 2, 2029.
(4) 
Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, asset retirement obligations, unrecognized tax benefits, contingency accruals and deferred revenue, which were included in “Other non-current liabilities” in our consolidated balance sheets were excluded from the table above as suchthe amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain.
(5)(4) 
Excludes net non-current deferred tax liabilities of $4.33$3.32 billion due to uncertainty of the timing of future cash flows for such liabilities.
Cash Distributions
Cash Distributions Paid by the Parent Company
Under the Parent Company Partnership Agreement, the Parent Company will distribute all of its Available Cash, as defined, within 50 days following the end of each fiscal quarter. Available cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner that is necessary or appropriate to provide for future cash requirements.

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Distributions declared and paid during the periods presented are as follows:
Quarter Ended            Record Date  Payment Date  Rate
December 31, 2011  February 7, 2012 February 17, 2012  $0.3125
March 31, 2012 May 4, 2012 May 18, 2012  0.3125
June 30, 2012 August 6, 2012 August 17, 2012  0.3125
September 30, 2012 November 6, 2012 November 16, 2012  0.3125
December 31, 2012 February 7, 2013 February 19, 2013  0.3175
March 31, 2013 May 6, 2013 May��17, 2013  0.3225
June 30, 2013 August 5, 2013 August 19, 2013  0.3275
September 30, 2013 November 4, 2013 November 19, 2013  0.3363
December 31, 2013 February 7, 2014 February 19, 2014  0.3463
March 31, 2014 May 5, 2014 May 19, 2014  0.3588
June 30, 2014 August 4, 2014 August 19, 2014  0.3800
September 30, 2014 November 3, 2014 November 19, 2014  0.4150
December 31, 2014 February 6, 2015 February 19, 2015 0.4500
Quarter Ended            Record Date  Payment Date  Rate
December 31, 2014 February 6, 2015 February 19, 2015 $0.2250
March 31, 2015 May 8, 2015 May 19, 2015 0.2450
June 30, 2015 August 6, 2015 August 19, 2015 0.2650
September 30, 2015 November 5, 2015 November 19, 2015 0.2850
December 31, 2015 February 4, 2016 February 19, 2016 0.2850
March 31, 2016 (1)
 May 6, 2016 May 19, 2016 0.2850
June 30, 2016 (1)
 August 8, 2016 August 19, 2016 0.2850
September 30, 2016 (1)
 November 7, 2016 November 18, 2016 0.2850
December 31, 2016 (1)
 February 7, 2017 February 21, 2017 0.2850
March 31, 2017 May 10, 2017 May 19, 2017 0.2850
June 30, 2017 August 7, 2017 August 21, 2017 0.2850
September 30, 2017 November 7, 2017 November 20, 2017 0.2950
December 31, 2017 February 8, 2018 February 20, 2018 0.3050
(1)
Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note 8 to the Partnership’s consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Our distributions declared and paid with respect to our Convertible Unit during the year ended December 31, 2017 were as follows:
Quarter Ended          Record Date Payment Date  Rate
March 31, 2016 May 6, 2016 May 19, 2016 $0.1100
June 30, 2016 August 8, 2016 August 19, 2016 0.1100
September 30, 2016 November 7, 2016 November 18, 2016 0.1100
December 31, 2016 February 7, 2017 February 21, 2017 0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100
December 31, 2017 February 8, 2018 February 20, 2018 0.1100

The total amounts of distributions declared and paid during the periods presented (all from Available Cash from the Parent Company’s operating surplus and are shown in the period to which they relate) are as follows:
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Limited Partners$866
 $748
 $703
$1,022
 $971
 $1,139
General Partner interest2
 2
 1
3
 3
 2
Class D units2
 —
 —
—
 —
 3
Total Parent Company distributions$870
 $750
 $704
$1,025
 $974
 $1,144
Cash Distributions Received by the Parent Company
The Parent Company’s cash available for distributions is primarily generated from its direct and indirect interests in ETP and Regency.Sunoco LP. Lake Charles LNG’s wholly-owned subsidiaries also contribute to the Parent Company’s cash available for distributions. OurAt December 31, 2017, our interests in ETP and Regency consistSunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as the following:approximately 27.5 million ETP common units, approximately 2.3 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries.
 ETP Regency
Units held by wholly-owned subsidiaries:   
Common units30.8
 57.2
ETP Class H units50.2
 —
Units held by less than wholly-owned subsidiaries:   
Common units—
 31.4
Regency Class F units—
 6.3
Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.
As the holder of ETP’s and Regency’sEnergy Transfer Partners, L.P.’s IDRs, the Parent Company ishas historically been entitled to an increasing share of ETP’s and Regency’sEnergy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of (i) ETP’s general partner interest, Class HI units and a portion of the outstanding ETP common units and (ii) Regency’s general partner interest and a portion of the outstanding Regency common units.

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 Percentage of Total Distributions to IDRs Quarterly Distribution Rate Target Amounts
  ETP Regency
Minimum quarterly distribution—% $0.25 $0.35
First target distribution—% $0.25 to $0.275 $0.35 to $0.4025
Second target distribution13% $0.275 to $0.3175 $0.4025 to $0.4375
Third target distribution23% $0.3175 to $0.4125 $0.4375 to $0.5250
Fourth target distribution48% Above $0.4125 Above $0.5250
Percentage of Total Distributions to IDRsETP
Quarterly Distribution Rate Target Amounts
Minimum Quarterly Distribution—%$0.0750
First Target Distribution—%up to $0.0833
Second Target Distribution13%above $0.0833 up to $0.0958
Third Target Distribution35%above $0.0958 up to $0.2638
Thereafter48%above $0.2638
Percentage of Total Distributions to IDRsSunoco LP
Quarterly Distribution Rate Target Amounts
Minimum quarterly distribution—%$0.4375
First target distribution—%$0.4375 to $0.503125
Second target distribution15%$0.503125 to $0.546875
Third target distribution25%$0.546875 to $0.656250
Fourth target distribution50%Above $0.656250

The total amount of distributions to the Parent Company and its wholly-owned subsidiaries received from ETP and Regency relating to its limited partner interests, general partner interest and incentive distributions (shown in the period to which they relate) for the periods ended as noted below is as follows:
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Distributions from ETP:          
Limited Partners$119
 $268
 $180
$61
 $28
 $54
Class H Units held by ETE Holdings219
 105
 —
Class H Units—
 357
 263
General Partner interest21
 20
 20
16
 32
 31
Incentive distributions754
 701
 529
IDR relinquishments related to previous transactions(250) (199) (90)
IDRs1,638
 1,363
 1,261
IDR relinquishments net of Class I Unit distributions(656) (409) (111)
Total distributions from ETP863
 895
 639
1,059
 1,371
 1,498
Distributions from Regency:     
Limited Partners99
 48
 48
General Partner interest6
 5
 5
Incentive distributions33
 12
 8
IDR relinquishments related to previous transaction(3) (3) —
Total distributions from Regency135
 62
 61
Distributions from Sunoco LP (1)
     
Limited Partner interests7
 7
 —
IDRs85
 81
 25
Series A Preferred23
 —
 —
Total distributions received from subsidiaries$998
 $957
 $700
$1,174
 $1,459
 $1,523
In connection with transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods based on (i) the currently effective partnership agreement provisions, (ii) the assumed closing of the issuance of additional ETP Class H Units and ETP Class I Units, which is expected to occur in March 2015, and (iii) the assumed closing of the Regency Merger, which is expected to occur in the second quarter of 2015:
Years Ending December 31, Currently Effective 
Pro Forma for
ETP Class H and
Class I Units(1)
 
Pro Forma for Regency Merger(2)
2015 $86
 $31
 $91
2016 107
 77
 142
2017 85
 85
 145
2018 80
 80
��140
2019 70
 70
 130
2020 35
 35
 50
2021 35
 35
 35
2022 35
 35
 35
2023 35
 35
 35
2024 18
 18
 18

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(1) 
Pro forma amounts reflectEffective July 1, 2015, ETE acquired 100% of the IDR subsidies, as adjusted formembership interests of Sunoco GP, the pending issuancegeneral partner of additional ETP Class H UnitsSunoco LP, and ETP Class I Units discussed above, as well as distributions onall of the ETP Class I Units. The issuanceIDRs of additional ETP Class H Units and ETP Class I Units is expected to close in March 2015.
(2)
Pro forma amounts reflect the IDR subsidies, as adjusted for (i) the pending issuanceSunoco LP from ETP. Effective January 1, 2016, ETE acquired 2,263,158 common units of additional ETP Class H Units and ETP Class I Units (as described in Note (1) above) and (ii) the pending Regency Merger. Amounts reflected above assume that the Regency Merger is closed subsequent to the record date for the first quarter of 2015 distribution payment and prior to the record date for the second quarter 2015 distribution payment.Sunoco LP.
TheIn connection with previous transactions, ETE has agreed to relinquish certain amounts reflected above include the relinquishment of $350 million in the aggregate of incentive distributions, that would potentially be made to ETE overincluding the first forty fiscal quarters commencing immediately after the consummationfollowing amounts of the Susser Merger. Such relinquishments would cease upon the agreement of an exchange of the Sunoco LP general partner interest and theincentive distributions in future periods. These amounts include incentive distribution rights between ETErelinquishments related to both legacy ETP and ETP.legacy Sunoco Logistics, both of which are applicable to the combined post-merger ETP:
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Cash Distributions Paid by Subsidiaries
Certain of our subsidiaries are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.
Cash Distributions Paid by ETP
ETP expects to use substantially all of its cash provided by operating and financing activities from its operating companies to provide distributions to its Unitholders. Under ETP’s limited partnership agreement, ETP will distribute to its partners within 45 days after the end of each calendar quarter, an amount equal to all of its Available Cash (as defined in ETP’s partnership agreement) for such quarter. Available Cash generally means, with respect to any quarter of ETP distributes all cash on hand at the end of suchthe quarter, less the amount of cash reserves established by ETP’s General Partnerthe general partner in its reasonablediscretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that isit determines are necessary or appropriate to provide for futureproperly conduct ETP’s business. ETP will make quarterly distributions to the extent there is sufficient cash requirements.from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”

The following table shows the target distribution levels and distribution “splits” between the general and limited partners and the holders of ETP’s commitment to its Unitholders is to distributeincentive distribution rights (”IDRs”):
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount IDRs 
Partners (1)
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%
(1) Includes general partner and limited partner interests, based on the increase in its cash flow while maintaining prudent reserves for its operations.proportionate ownership of each.
Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:
Quarter Ended ETP Sunoco Logistics
December 31, 2014 $0.6633
 $0.4000
March 31, 2015 0.6767
 0.4190
June 30, 2015 0.6900
 0.4380
September 30, 2015 0.7033
 0.4580
December 31, 2015 0.7033
 0.4790
March 31, 2016 0.7033
 0.4890
June 30, 2016 0.7033
 0.5000
September 30, 2016 0.7033
 0.5100
December 31, 2016 0.7033
 0.5200
Distributions on common units declared and paid by Post-Merger ETP were as follows:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 16, 2017 $0.5350
June 30, 2017 August 7, 2017 August 15, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
December 31, 2017 February 8, 2018 February 14, 2018 0.5650
Distributions declared and paid by ETP duringto the periods presented areETP Series A and Series B preferred unitholders were as follows:
  Record Date  Payment Date  Rate
December 31, 2011 February 7, 2012 February 14, 2012 $0.8938
March 31, 2012 May 4, 2012 May 15, 2012 0.8938
June 30, 2012 August 6, 2012 August 14, 2012 0.8938
September 30, 2012 November 6, 2012 November 14, 2012 0.8938
December 31, 2012 February 7, 2013 February 14, 2013 0.8938
March 31, 2013 May 6, 2013 May 15, 2013 0.8938
June 30, 2013 August 5, 2013 August 14, 2013 0.8938
September 30, 2013 November 4, 2013 November 14, 2013 0.9050
December 31, 2013 February 7, 2014 February 14, 2014 0.9200
March 31, 2014 May 5, 2014 May 15, 2014 0.9350
June 30, 2014 August 4, 2014 August 14, 2014 0.9550
September 30, 2014 November 3, 2014 November 14, 2014 0.9750
December 31, 2014 February 6, 2015 February 13, 2015 0.9950
 Distribution per Preferred Unit
Quarter Ended Record Date Payment Date Series A Series B
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
 $16.378


The total amounts of distributions declared and paid during the periods presented (all from Available Cash from ETP’s operating surplus and are shown in the period to which they relate) are as follows (in millions):
 Years Ended December 31,
 2014 2013 2012
Limited Partners:     
  Common Units$1,298
 $1,265
 $955
  Class H Units219
 105
 —
General Partner interest21
 20
 20
Incentive distributions754
 701
 529
IDR relinquishments related to previous transactions(250) (199) (90)
Total ETP distributions$2,042
 $1,892
 $1,414

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Cash Distributions Paid by Sunoco Logistics
Sunoco Logistics is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by its general partner.
Distributions declared during the periods presented were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2012 February 8, 2013 February 14, 2013 $0.2725
March 31, 2013 May 9, 2013 May 15, 2013 0.2863
June 30, 2013 August 8, 2013 August 14, 2013 0.3000
September 30, 2013 November 8, 2013 November 14, 2013 0.3150
December 31, 2013 February 10, 2014 February 14, 2014 0.3312
March 31, 2014 May 9, 2014 May 15, 2014 0.3475
June 30, 2014 August 8, 2014 August 14, 2014 0.3650
September 30, 2014 November 7, 2014 November 14, 2014 0.3825
December 31, 2014 February 9, 2015 February 13, 2015 0.4000
 Years Ended December 31,
 ETP Energy Transfer Partners, L.P. Sunoco Logistics
 2017 2016 2015 2016 2015
Common Units held by public$2,435
 $2,168
 $1,970
 $485
 $344
Common Units held by ETP—
 —
 —
 135
 120
Common Units held by ETE61
 28
 54
 —
 —
Class H Units held by ETE—
 357
 263
 —
 —
General Partner interest16
 32
 31
 15
 12
Incentive distributions1,638
 1,363
 1,261
 397
 281
IDR relinquishments (1)
(656) (409) (111) (15) —
ETP Series A Preferred Units15
 —
 —
 —
 —
ETP Series B Preferred Units9
 —
 —
 —
 —
Total distributions declared to partners$3,518
 $3,539
 $3,468
 $1,017
 $757
Sunoco Logistics Unit Split
On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis.
The total amounts of Sunoco Logistics distributions declared during the periods presented were as follows (all from Available Cash from Sunoco Logistics’ operating surplus and are shown in the period with respect to which they relate):
 Years Ended December 31,
 2014 2013 2012
Limited Partners     
Common units held by public$225
 $173
 $39
Common units held by ETP100
 82
 18
General Partner interest held by ETP10
 5
 1
Incentive distributions held by ETP175
 117
 22
Total distributions declared$510
 $377
 $80
(1)
Net of Class I unit distributions
Cash Distributions Paid by Sunoco LP
Sunoco LP is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by its general partner.
Distributions declared and paid by Sunoco LP subsequent to our acquisition on August 29, 2014during the periods presented were as follows:
Quarter Ended Record Date Payment Date Rate Record Date Payment Date Rate
September 30, 2014 November 18, 2014 November 28, 2014 $0.5457
December 31, 2014 February 17, 2015 February 27, 2015 0.6000
 February 17, 2015 February 27, 2015 $0.6000
March 31, 2015 May 19, 2015 May 29, 2015 0.6450
June 30, 2015 August 18, 2015 August 28, 2015 0.6934
September 30, 2015 November 17, 2015 November 27, 2015 0.7454
December 31, 2015 February 5, 2016 February 16, 2016 0.8013
March 31, 2016 May 6, 2016 May 16, 2016 0.8173
June 30, 2016 August 5, 2016 August 15, 2016 0.8255
September 30, 2016 November 7, 2016 November 15, 2016 0.8255
December 31, 2016 February 13, 2017 February 21, 2017 0.8255
March 31, 2017 May 9, 2017 May 16, 2017 0.8255
June 30, 2017 August 7, 2017 August 15, 2017 0.8255
September 30, 2017 November 7, 2017 November 14, 2017 0.8255
December 31, 2017 February 06, 2018 February 14, 2018 0.8255

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The total amounts of Sunoco LP distributions declared and paid during the periods presented were as follows (all from Available Cash from Sunoco Logistics’LP’s operating surplus and are shown in the period with respect to which they relate):
Years Ended December 31,
Year Ended December 31, 20142017 2016 2015
Limited Partners:      
Common units held by public$22
$178
 $166
 $90
Common units held by ETP17
General Partner interest and incentive distributions held by ETP1
Common and subordinated units held by ETP(1)
143
 143
 89
Common and subordinated units held by ETE7
 8
 —
General Partner interest and Incentive distributions(2)
85
 81
 30
Series A Preferred23
 —
 —
Total distributions declared$40
$436
 $398
 $209
(1)
Includes Sunoco LP units issued to ETP in connection with Sunoco LP’s acquisition of Susser from ETP in July 2015.
(2)
The Sunoco LP IDRs were held by ETP until July 2015, at which time the IDRs were exchanged with ETE. The total incentive distributions from Sunoco LP for the year ended December 31, 2015 include $5 million to ETP and 25 million to ETE related to the respective periods during which each held the IDRs.
Cash Distributions Paid by RegencyRecent Accounting Pronouncements
Regency’s partnership agreement requires that Regency distribute all of its Available Cash to its Unitholders and its General Partner within 45 days after the end of each quarter to unitholders of record on the applicable record date, as determined by the general partner. The term Available Cash generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the general partner to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to the unitholders and to the General Partner for any one or more of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.
Distributions declared by Regency during the periods presented are as follows:
Quarter Ended  Record Date  Payment Date  Rate
December 31, 2011 February 6, 2012 February 13, 2012 $0.4600
March 31, 2012 May 7, 2012 May 14, 2012 0.4600
June 30, 2012 August 6, 2012 August 14, 2012 0.4600
September 30, 2012 November 6, 2012 November 14, 2012 0.4600
December 31, 2012 February 7, 2013 February 14, 2013 0.4600
March 31, 2013 May 6, 2013 May 13, 2013 0.4600
June 30, 2013 August 5, 2013 August 14, 2013 0.4650
September 30, 2013 November 4, 2013 November 14, 2013 0.4700
December 31, 2013 February 7, 2014 February 14, 2014 0.4750
March 31, 2014 May 8, 2014 May 15, 2014 0.4800
June 30, 2014 August 7, 2014 August 14, 2014 0.4900
September 30, 2014 November 4, 2014 November 14, 2014 0.5025
December 31, 2014 February 6, 2015 February 13, 2015 0.5025
The total amounts of Regency distributions declared (all from Regency’s operating surplus and are shown in the period with respect to which they relate) are as follows:
 Years Ended December 31,
2014 2013 2012
Limited Partners$775
 $390
 $314
General Partner Interest6
 5
 5
Incentive distributions33
 12
 8
IDR relinquishments related to previous transactions(3) (3) —
Total Regency distributions$811
 $404
 $327

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New Accounting StandardsASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“(“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.
For future periods, ETP expects that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of its midstream agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.
We have determined that the timing and/or amount of revenue that we recognize on certain contracts associated with Sunoco LP’s operations will be impacted by the adoption of the new standard. We currently estimate the cumulative catch-up effect to Sunoco LP’s retained earnings as of January 1, 2018 to be approximately $54 million. These adjustments are primarily related to the change in recognition of dealer incentives and rebates.
ASU 2016-02
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-16
On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.

ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.
ASU 2017-12
In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for annual reportingfinancial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, including interim periods within that reporting period,2018, with earlierearly adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact if any, that adopting this new accounting standard will have on our revenue recognition policies.the consolidated financial statements and related disclosures.
In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations.  Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results.  ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.
Estimates and Critical Accounting Policies
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our critical accounting policies are discussed below. For further details on our accounting policies, see Note 2 to our consolidated financial statements.
Use of Estimates.  The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for theETP’s midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the year ended December 31, 20142017 represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Revenue Recognition.  Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing, are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
The results of ETP’s intrastate transportation and storage and interstate transportation operations are determined primarily by the amount of capacity ETP’s customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, ETP customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Excess fuel retained after consumption is typically valued at market prices.
ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL

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System. Generally, ETP purchases natural gas from the market, including purchases from the midstream marketing operations, and from producers at the wellhead.

In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and grosssegment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.
ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
ETP has a risk management policy that provides for oversight over ETP’s marketing activities. These activities are monitored independently by ETP’s risk management function and must take place within predefined limits and authorizations. As a result of ETP’s use of derivative financial instruments that may not qualify for hedge accounting, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attempts to manage this volatility through the use of daily position and profit and loss reports provided to senior management and predefined limits and authorizations set forth in ETP’s risk management policy.
ETP injects and holds natural gas in our Bammel storage facility to take advantage of contango markets, when the price of natural gas is higher in the future than the current spot price. ETP uses financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, ETP locks in a margin by purchasing gas in the spot market or off peak season and entering a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot prices result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot prices and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that ETP recognizes in earnings the original locked in spread, either through mark-to-market or the physical withdrawal of natural gas.

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ETP’s NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third partythird-party pipeline, which is when title and risk of loss pass to the customer.

In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
ETP’s retail marketing operations sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease whit the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas gathering, processing and transportation, (iii) contract compression services and (iv) contract treating services. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percent-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas at a price approximating the index price and NGLs to third parties. Regency generally reports revenue gross when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net because Regency takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.
Regulatory Assets and Liabilities.  Certain of our subsidiaries are subject to regulation by certain state and federal authorities and have accounting policies that conform to FASB Accounting Standards Codification (“ASC”) Topic 980, Regulated Operations, which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be assessed and potentially eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Accounting for Derivative Instruments and Hedging Activities.  ETP and Regency utilizeutilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit their exposure to margin fluctuations in natural gas, NGL and refined products. These contracts consist primarily of commodity futures and swaps. In addition, prior to ETP’s contribution of its retail propane activities to AmeriGas, ETP used derivatives to limit its exposure to propane market prices.

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If ETP or Regency designatedesignates a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
If ETP or Regency designatedesignates a hedging relationship as a fair value hedge, they record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
ETP and Regency utilizeutilizes published settlement prices for exchange-traded contracts, quotes provided by brokers, and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” for further discussion regarding our derivative activities.
Fair Value of Financial Instruments.  We have marketable securities, commodity derivatives, interest rate derivatives the Preferred Units and embedded derivatives in the RegencyETP Convertible Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider over-the-counterOTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our

interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 utilizes significant unobservable inputs. Level 3 inputs are unobservable. Derivatives related to the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility, and are considered Level 3. See further information on our fair value assets and liabilities in Note 2 of our consolidated financial statements.
Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Goodwill.Investments in Unconsolidated Affiliates.  Long-lived assets are required to be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair value.
In order to test for recoverability when performing a quantitative impairment test, we must makethe Partnership makes estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we makethe Partnership makes certain estimates and assumptions, including, among other things, changes in general economic conditions in the Partnership’s operating regions, in which our markets are located, the availability and prices of natural gas, ourthe ability to negotiate favorable sales agreements, the risks that natural gas exploration and production activities will not occur or be successful, our dependence on certain significant customers and producers of natural gas, and competition from other companies, including major energy producers. While we believe we have made reasonable assumptions to calculate the fair value, ifIf future results are not consistent with ourthe Partnership’s estimates, we could be exposed to future impairment losses that could be material may be recorded to our results of operations.
The Partnership determined the fair value of its reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable; however, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
One key assumption for the measurement of an impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item 1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in additional impairments in future periods; however, management does not believe that any of the goodwill balances in its reporting units as of December 31, 2017 is at significant risk of impairment. Therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant changes in fair value estimates could occur in a given period, resulting in additional impairments. 
Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the $4.8 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2017, approximately $1.0 billion is recorded in ETP’s reporting units for which the estimated fair value exceeded the carrying value by less than 20% in the most recent quantitative test.
During the year ended December 31, 2017, ETP recorded following impairments:
A $223 million impairment was recorded related to the goodwill associated with CDM. In January 2018, ETP announced the contribution of CDM to USAC. Based on ETP’s anticipated proceeds in the contribution transaction, the implied fair value

of the CDM reporting unit was less than its carrying value. As ETP believes that the contribution consideration also represented an appropriate estimate of fair value as of the 2017 annual impairment test date, ETP recorded an impairment for the difference between the carrying value and the fair value of the reporting unit. Subsequent to the impairment, a total of $253 million of goodwill remains in the CDM reporting unit, which amount is subject to further impairment based on changes in the contribution transaction prior to closing or any other factors affecting the fair value of the CDM reporting unit. Assuming the contribution transaction closes, the remaining CDM goodwill balance will be derecognized; if the transaction does not close, then the CDM goodwill balance will remain on the ETP’s consolidated balance sheet and will continue to be tested for impairment in the future.
A $262 million impairment was recorded related to the goodwill associated with ETP’s interstate transportation and storage reporting units, and a $229 million impairment was recorded related to the goodwill associated with the general partner of Panhandle. These impairments were due to a reduction in management’s forecasted future cash flows from the related reporting units, which reduction reflected the impacts discussed in “Results of Operations” above, along with the impacts of re-contracting assumptions related to future periods.
A $79 million impairment was recorded related to the goodwill associated ETP’s refined products transportation and services reporting unit. Subsequent to the Sunoco Logistics Merger, ETP restructured the internal reporting of legacy Sunoco Logistics’ business to be consistent with the internal reporting of legacy ETP. Subsequent to this reallocation the carrying value of certain refined products reporting units was less than the estimated fair value due to a reduction in management’s forecasted future cash flows from the related reporting units, and the goodwill associated with those reporting units was fully impaired. No goodwill remained in the respective reporting units subsequent to the impairment.
A $127 million impairment of property, plant and equipment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets.
A $141 million impairment of ETP’s equity method investment in FEP. ETP concluded that the carrying value of its investment in FEP was other than temporarily impaired based on an anticipated decrease in production in the Fayetteville basin and a customer re-contracting with a competitor during 2017.
A $172 million impairment of ETP’s equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven be the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.
During the year ended December 31, 2016, ETP recorded following goodwill impairments:
A $638 million goodwill impairment and a $133 million impairment to property, plant and equipment were recorded in its interstate transportation and storage operations primarily due to decreases in projected future revenues and cash flows driven by changes in the markets that these assets serve.
A $32 million goodwill impairment was recorded in its midstream operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices.
A $308 million impairment of ETP’s equity method investment in MEP. ETP concluded that the carrying value of its investment in MEP was other than temporarily impaired based on commercial discussions with current and potential shippers on MEP during 2016, which negatively affected the outlook for long-term transportation contract rates.
During the year ended December 31, 2015, ETP recorded following goodwill impairments:
A $99 million goodwill impairment related to Transwestern primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.
A $106 million goodwill impairment, a $24 million impairment of intangible assets, and a $110 million impairment to property, plant and equipment related to Lone Star Refinery Services primarily due to changes in assumptions related to potential future revenues and market declines in current and expected future commodity prices, as well as economic obsolescence identified as a result of low utilization.
Except for the 2017 impairment of the goodwill associated with CDM, as discussed above, the goodwill impairments recorded by ETP during the years ended December 31, 2017, 2016 and 2015 represented all of the goodwill within the respective reporting units.
For Sunoco LP, the impairment of $641 million during the year ended December 31, 2016 represented a portion of the goodwill within Sunoco LP’s retail reporting unit.

During 2017, Sunoco LP announced the sale of a majority of the assets in its retail and Stripes reporting units. These reporting units include the retail operations in the continental United States but excludes the retail convenience store operations in Hawaii that comprise the Aloha reporting unit. Upon the classification of assets and related liabilities as held for sale, Sunoco LP’s management applied the measurement guidance in ASC 360, Property, Plant and Equipment, to calculate the fair value less cost to sell of the disposal group. In accordance with ASC 360-10-35-39, Sunoco LP’s management first tested the goodwill included within the disposal group for impairment prior to measuring the disposal group’s fair value less the cost to sell. In the determination of the classification of assets held for sale and the related liabilities, Sunoco LP’s management allocated a portion of the goodwill balance previously included in the Sunoco LP retail and Stripes reporting units to assets held for sale based on the relative fair values of the business to be disposed of and the portion of the respective reporting unit that will be retained in accordance with ASC 350-20-40-3. The amount of goodwill allocated to assets held for sale was approximately $796 million and $1.1 billion as of December 31, 2017 and 2016, respectively. The remainder of the goodwill was allocated to the retained portion of the retail and Stripes reporting units, which is comprised of Sunoco LP’s ethanol plant, credit card processing services, franchise royalties and retail stores Sunoco LP continues to operate in the continental United States. This amount, inclusive of the portion of the Aloha reporting unit that represents retail activities, was approximately $678 million and $780 million as of December 31, 2017 and 2016, respectively.
Sunoco LP recognized goodwill impairments of $387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
For goodwill included in the Aloha and Wholesale reporting units, which goodwill balances total $112 million and $732 million, respectively, and which were not classified as held for sale, no impairments were deemed necessary during 2017.
Additionally, Sunoco LP performed impairment tests on their indefinite-lived intangible assets during the fourth quarter of 2017 and recognized $13 million and $4 million impairment charge on their contractual rights and liquor licenses primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded.
Property, Plant and Equipment.  Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, ETP capitalizes certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in the consolidated statement of operations. Depreciation of property, plant and equipment is provided using the straight-line method based on their estimated useful lives ranging from 1 to 99 years. Changes in the estimated useful lives of the assets could have a

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material effect on our results of operation. We do not anticipate future changes in the estimated useful lives of our property, plant and equipment.
Asset Retirement Obligations.   We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be levelLevel 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts recorded by Panhandle, Sunoco Logistics and ETP’s retail marketing operations discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 20142017 and 2013,2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes itWe believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
AsLong-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2014, there were no2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million of legally restricted funds for the purpose of settling AROs.AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.
Pensions and Other Postretirement Benefit Plans. We are required to measure plan assets and benefit obligations as of its fiscal year-end balance sheet date. We recognize the changes in the funded status of our defined benefit postretirement plans through AOCI or are reflected as a regulatory asset or regulatory liability for regulated subsidiaries.
The calculation of the net periodic benefit cost and benefit obligation requires the use of a number of assumptions. Changes in these assumptions can have a significant effect on the amounts reported in the financial statements. The Partnership believes that the two most critical assumptions are the assumed discount rate and the expected rate of return on plan assets.
The discount rate is established by using a hypothetical portfolio of high-quality debt instruments that would provide the necessary cash flows to pay the benefits when due. Net periodic benefit cost and benefit obligation increases and equity correspondingly decreases as the discount rate is reduced.
The expected rate of return on plan assets is based on long-term expectations given current investment objectives and historical results. Net periodic benefit cost increases as the expected rate of return on plan assets is correspondingly reduced.
Legal Matters.  We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised as required as better information becomes available to us. The factors we consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience; and (iii) the decision of our management as to how we intend to respond to the complaints.
For more information on our litigation and contingencies, see Note 1211 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” in this report.
Environmental Remediation Activities. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual

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for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and reasonably estimable. ETP has established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, ETP accrues losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded. ETP’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded.

In addition to the probable and estimable losses which have been recorded, management believes it is reasonably possible (i.e., less than probable but greater than remote) that additional environmental remediation losses will be incurred. At December 31, 2014,2017, the aggregate of the estimated maximum additional reasonably possible losses, which relate to numerous individual sites, totaled approximately $6$5 million. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics and retail assets and, in many cases, reflects the upper end of the loss ranges which are described above. Such estimates include potentially higher contractor costs for expected remediation activities, the potential need to use more costly or comprehensive remediation methods and longer operating and monitoring periods, among other things.
Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position.
Deferred Income Taxes. ETE recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal tax alternative minimum tax credit carryforwards totaling $116$683 million have been included in ETE’s consolidated balance sheet as of December 31, 2014.2017. All of the deferred income tax assets attributable to state and federal NOL benefits expire before 20332037 as more fully described below. The state NOL carryforward benefits of $111$274 million (net($217 million net of federal benefit) begin to expire in 20142018 with a substantial portion expiring between 20292031 and 2033.2037. The federal NOLs of $5$1,921 million ($1403 million in benefits) will expire in 20322033 and 2033. Less than $1 million of federal2036. Federal tax alternative minimum tax credit carryforwards of $62 million remained at December 31, 2014.2017. We have determined that a valuation allowance totaling $84$236 million (net($186 million net of federal income tax effects) is required for the state NOLs at December 31, 20142017 primarily due to significant restrictions on their use in the Commonwealth of Pennsylvania. In making the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.

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Forward-Looking Statements
This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;
the actual amount of cash distributions by our subsidiaries to us;
the volumes transported on our subsidiaries’ pipelines and gathering systems;

the level of throughput in our subsidiaries’ processing and treating facilities;
the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;
the prices and market demand for, and the relationship between, natural gas and NGLs;
energy prices generally;
the prices of natural gas and NGLs compared to the price of alternative and competing fuels;
the general level of petroleum product demand and the availability and price of NGL supplies;
the level of domestic oil, natural gas and NGL production;
the availability of imported oil, natural gas and NGLs;
actions taken by foreign oil and gas producing nations;
the political and economic stability of petroleum producing nations;
the effect of weather conditions on demand for oil, natural gas and NGLs;
availability of local, intrastate and interstate transportation systems;
the continued ability to find and contract for new sources of natural gas supply;
availability and marketing of competitive fuels;
the impact of energy conservation efforts;
energy efficiencies and technological trends;
governmental regulation and taxation;
changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;
hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
competition from other midstream companies and interstate pipeline companies;
loss of key personnel;
loss of key natural gas producers or the providers of fractionation services;
reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities;
the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their financial commitments;
the nonpayment or nonperformance by our subsidiaries’ customers;
regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our subsidiaries’ internal growth projects, such as our subsidiaries’ construction of additional pipeline systems;

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risks associated with the construction of new pipelines and treating and processing facilities or additions to our subsidiaries’ existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors;
the availability and cost of capital and our subsidiaries’ ability to access certain capital sources;
a deterioration of the credit and capital markets;
risks associated with the assets and operations of entities in which our subsidiaries own less than a controlling interests, including risks related to management actions at such entities that our subsidiaries may not be able to control or exert influence;

the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses;
changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; and
the costs and effects of legal and administrative proceedings.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.
Inflation
Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances.
Inflation in the United States has been relatively low in recent years and has not had a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by commodity price changes. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
(Tabular dollar amounts are in millions)
Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risk and interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream operations whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other operations which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The tables below summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in the underlying price of the commodity as of December 31, 20142017 and 20132016 for ETP and Regency,Sunoco LP, including derivatives related to their respective subsidiaries. Notional volumes are presented in MMBtu for natural gas, thousand megawatt for power and barrels for natural gas liquids, crude and refined products. Dollar amounts are presented in millions.
 December 31, 2017 December 31, 2016
 Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change
Mark-to-Market Derivatives           
(Trading)           
Natural Gas (BBtu):           
Fixed Swaps/Futures1,078
 $—
 $—
 (683) $—
 $—
Basis Swaps IFERC/NYMEX(1)
48,510
 2
 1
 2,243
 (1) —
Options – Puts13,000
 —
 —
 —
 —
 —
Power (Megawatt):           
Forwards435,960
 1
 1
 391,880
 (1) 1
Futures(25,760) —
 —
 109,564
 —
 —
Options — Puts(153,600) —
 1
 (50,400) —
 —
Options — Calls137,600
 —
 —
 186,400
 1
 —
Crude (MBbls) — Futures—
 1
 —
 (617) (4) 6
(Non-Trading)           
Natural Gas (BBtu):           
Basis Swaps IFERC/NYMEX4,650
 (13) 4
 10,750
 2
 —
Swing Swaps IFERC87,253
 (2) 1
 (5,663) (1) 1
Fixed Swaps/Futures(4,390) (1) 2
 (52,653) (27) 19
Forward Physical Contracts(145,105) 6
 41
 (22,492) 1
 —
Natural Gas Liquid (MBbls) — Forwards/Swaps6,744
 1
 25
 (5,787) (40) 35
Refined Products (MBbls) — Futures(3,901) (27) 4
 (3,144) (21) 18
Corn (Bushels) – Futures1,870,000
 —
 —
 1,580,000
 —
 1
Fair Value Hedging Derivatives           
(Non-Trading)           
Natural Gas (BBtu):           
Basis Swaps IFERC/NYMEX(39,770) (2) —
 (36,370) 2
 1
Fixed Swaps/Futures(39,770) 14
 11
 (36,370) (26) 14
(1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
The fair values of the commodity-related financial positions have been determined using independent third partythird-party prices, readily available market information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the below tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt month natural gas prices, the fair value of our total derivative portfolios may not change by 10% due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

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Our consolidated balance sheets also reflect assets and liabilities related to commodity derivatives that have previously been de-designated as cash flow hedges or for which offsetting positions have been entered. Those amounts are not subject to change based on changes in prices.
Investment in ETP
For certain of ETP’s activities, it is exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, ETP utilizes various exchange-traded and over-the-counter commodity financial instrument contracts. These contracts consist primarily of futures and swaps and are recorded at fair value in the consolidated balance sheets. In general, ETP uses derivatives to reduce market exposure and price risk within its operations as follows:
ETP uses derivative financial instruments in connection with its natural gas inventory at the Bammel storage facility by purchasing physical natural gas and then selling forward financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. ETP also uses derivatives in its intrastate transportation and storage operations to hedge the sales price of retention natural gas in excess of consumption, a portion of volumes purchased at the wellhead from producers, and location price differentials related to the transportation of natural gas. Additionally, ETP uses derivatives for trading purposes in these operations.
Derivatives are utilized in ETP’s midstream operations in order to mitigate price volatility in its marketing activities and manage fixed price exposure incurred from contractual obligations.
ETP also uses derivative swap contracts to mitigate risk from price fluctuations on NGLs it retains for fees in its midstream operations.
Sunoco Logistics uses derivative contracts as economic hedges against price changes related to its forecasted refined products and NGL purchase and sale activities.
In all other operations, ETP utilized derivatives for trading purposes.
The market prices used to value financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.
If ETP designates a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
If ETP designates a hedging relationship as a fair value hedge, ETP records the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in cost of products sold in our consolidated statements of operations.
ETP uses futures and basis swaps, designated as fair value hedges, to hedge its natural gas inventory stored in its Bammel storage facility. Changes in the spreads between the forward natural gas prices designated as fair value hedges and the physical Bammel inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
ETP attempts to maintain balanced positions to protect itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide most of the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. To the extent open commodity positions exist, fluctuating commodity prices can impact our financial position and results of operations, either favorably or unfavorably.
Sunoco Logistics manages exposures to crude oil, refined products and NGL commodity prices by monitoring inventory levels and expectations of future commodity prices when making decisions with respect to risk management and inventory carried. Sunoco Logistics’ policy is to purchase only commodity products for which it has a market and to structure its sales contracts so that price fluctuations for those products do not materially affect the margin Sunoco Logistics receives. Sunoco Logistics also seeks to maintain a position that is substantially balanced within its various commodity purchase and sale activities. Sunoco Logistics may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery

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variances, as well as logistical issues associated with inclement weather conditions. When unscheduled inventory builds or draws do occur, they are monitored and managed to a balanced position over a reasonable period of time.
 December 31, 2014 December 31, 2013
 Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change Notional Volume Fair Value Asset (Liability) Effect of Hypothetical 10% Change
Mark-to-Market Derivatives           
(Trading)           
Natural Gas (MMBtu):           
Fixed Swaps/Futures(232,500) $(1) $—
 9,457,500
 $3
 $5
Basis Swaps IFERC/NYMEX(1)
(13,907,500) —
 —
 (487,500) 1
 —
Swings Swaps IFERC—
 —
 —
 1,937,500
 1
 —
Options – Calls5,000,000
 —
 —
 —
 —
 —
Power (Megawatt):           
Forwards288,775
 —
 1
 351,050
 1
 1
Futures(156,000) 2
 —
 (772,476) —
 2
Options — Puts(72,000) —
 1
 (52,800) —
 —
Options — Calls198,556
 —
 —
 103,200
 —
 —
Crude (Bbls) — Futures—
 —
 —
 103,000
 —
 1
(Non-Trading)           
Natural Gas (MMBtu):           
Basis Swaps IFERC/NYMEX57,500
 (3) —
 570,000
 —
 —
Swing Swaps IFERC46,150,000
 2
 1
 (9,690,000) 1
 —
Fixed Swaps/Futures(8,779,000) 4
 2
 (8,195,000) 13
 3
Forward Physical Contracts(9,116,777) —
 3
 5,668,559
 (1) 2
Natural Gas Liquid (Bbls) — Forwards/Swaps(2,179,400) 13
 9
 (1,133,600) —
 3
Refined Products (Bbls) — Futures13,745,755
 15
 11
 (280,000) —
 17
Fair Value Hedging Derivatives           
(Non-Trading)           
Natural Gas (MMBtu):           
Basis Swaps IFERC/NYMEX(39,287,500) 3
 1
 (7,352,500) —
 —
Fixed Swaps/Futures(39,287,500) 48
 12
 (50,530,000) (11) 23
Cash Flow Hedging Derivatives           
(Non-Trading)           
Natural Gas (MMBtu):           
Basis Swaps IFERC/NYMEX—
 —
 —
 (1,825,000) —
 —
Fixed Swaps/Futures—
 —
 —
 (12,775,000) (3) 6
Natural Gas Liquid (Bbls) — Forwards/Swaps—
 —
 —
 (780,000) (1) 4
Crude (Bbls) — Futures—
 —
 —
 (30,000) —
 —
(1) Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Investment in Regency
Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand, as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its

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contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions are prohibited under Regency’s policy.
Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency GP have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency GP is responsible for delegation of transaction authority levels, and the Audit and Risk Committee of Regency GP is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency GP’s Audit and Risk Committee receives regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities.
Regency has swap contracts that settle against certain NGLs, condensate and natural gas market prices.
 December 31, 2014 December 31, 2013
 
Notional
Volume
 
Fair Value
Asset
(Liability)
 
Effect of
Hypothetical
10%
Change
 
Notional
Volume
 
Fair Value
Asset
(Liability)
 
Effect of
Hypothetical
10%
Change
Mark-to-Market Derivatives           
(Non-Trading)           
Natural Gas (MMBtu) — Fixed Swaps/Futures(25,525,000) $26
 $8
 (24,455,000) $(2) $10
Propane (Gallons) — Forwards/Swaps(29,148,000) 17
 1
 (52,122,000) (3) 6
NGLs (Barrels) — Forwards/Swaps(292,000) 6
 1
 (438,000) 1
 2
WTI Crude Oil (Barrels) — Forwards/Swaps(1,252,000) 36
 7
 (521,000) (1) 5

Interest Rate Risk
As of December 31, 2014, ETP2017, we and our subsidiaries had $2.04$9.86 billion of floating rate debt outstanding, Regency had $1.50 billionoutstanding. A hypothetical change of floating100 basis points would result in a maximum potential change to interest expense of $98 million annually; however, our actual change in interest expense may be less in a given period due to interest rate floors included in our variable rate debt outstanding under its revolving credit facilities and ETE had $2.34 billion of floating rate debt outstanding under its revolving credit facilities as of December 31, 2014.instruments. We manage a portion of our interest rate exposure by utilizing interest rate swaps. Toswaps, including forward-starting interest rate swaps to lock-in the extent that we haverate on a portion of anticipated debt with floating interest rates that are not hedged, our results of operations, cash flows and financial condition could be adversely affected by increases in interest rates.issuances.

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The following table summarizes our interest rate swaps outstanding, (dollars in millions), none of which are designated as hedges for accounting purposes:
     Notional Amount Outstanding     Notional Amount Outstanding
Entity Term 
Type(1)
 December 31, 2014 December 31, 2013 Term 
Type(1)
 December 31, 2017 December 31, 2016
ETP 
July 2014(2)
 Forward-starting to pay a fixed rate of 4.25% and receive a floating rate $—
 $400
 
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
ETP 
July 2015(2)
 Forward-starting to pay a fixed rate of 3.38% and receive a floating rate 200
 —
 
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
ETP 
July 2016(3)
 Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 200
 —
 
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
ETP 
July 2017(4)
 Forward-starting to pay a fixed rate of 3.84% and receive a floating rate 300
 —
 
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
ETP 
July 2018(4)
 Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200
 —
 December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
ETP 
July 2019(4)
 Forward-starting to pay a fixed rate of 3.19% and receive a floating rate 300
 —
 March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
ETP July 2018 Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% —
 600
ETP June 2021 Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% —
 400
ETP February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% 200
 400
Panhandle November 2021 Pay a fixed rate of 3.82% and receive a floating rate —
 275
(1) 
Floating rates are based on 3-month LIBOR.
(2)
Represents the effective date. These forward-starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.
(3)
Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
(4) 
Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.
A hypothetical change of 100 basis points in interest rates for these interest rate swaps would result in a change in the fair value of the interest rate derivatives and earnings (recognized in gains (losses) on interest rate derivatives) of approximately $214$236 million as of December 31, 2014.2017. For ETP’s $200 million$1.50 billion of interest rate swaps whereby it pays a floating rate and receives a fixed rate, a hypothetical change of 100 basis points in interest rates would result in a net change in annual cash flow of $2$15 million. For the forward-starting interest rate swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.
Credit Risk
Credit Riskrisk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. WeThe Partnership also implement the use ofuses industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies, and midstream companies.independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our

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counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
Regency’sbusiness operations expose it to credit risk, as the margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss can be very large relative to Regency’s overall profitability. Regency monitors credit exposure and attempts to ensure that it issues credit only to creditworthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral such as a letter of credit or a parent company guarantee.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheetsheets and recognized in net income or other comprehensive income.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements starting on page F-1 of this report are incorporated by reference.
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
ITEM 9A.  CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
An evaluation was performed under the supervision and with the participation of our management, including the President and Group Chief Financial Officer and Head of Business Development of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in RuleRules 13a–15(e) and 15d–15(e) of the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including the President and Group Chief Financial Officer and Head of Business Development of our General Partner, concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2014.2017.
Management’s Report on Internal Control over Financial Reporting
The management of Energy Transfer Equity, L.P. and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the President and Group Chief Financial Officer and Head of Business Development of our General Partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO Framework”).
On August 29, 2014, ETP and Susser completed the previously announced merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP (the “Susser Merger”). Management has acknowledged that it is responsible for establishing and maintaining a system of internal controls over financial reporting for Susser. We are in the process of integrating Susser, and we therefore excluded Susser from our December 31, 2014 assessment of the effectiveness of internal control over financial reporting. Susser had total assets of $2.68 billion at December 31, 2014 and third party revenue of $1.62 billion from August 29, 2014 to December 31, 2014 included in our consolidated financial statements as of and for the year ended December 31, 2014. The Susser Merger has not materially affected and is not expected to materially affect our internal control over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. We believe, however, that we will be able to maintain sufficient controls over the substantive results of our financial reporting throughout this integration process.
Our assessment of internal control over financial reporting did include an assessment of Sunoco LP, which ETP obtained control of in connection with the Susser Merger.
On July 1, 2014, our subsidiary Regency acquired Eagle Rock’s midstream business. Management has acknowledged that it is responsible for establishing and maintaining a system of internal controls over financial reporting for Eagle Rock. We are in the process of integrating Eagle Rock, and we therefore excluded Eagle Rock from our December 31, 2014 assessment of the effectiveness of internal control over financial reporting. Eagle Rock had total assets of $1.90 billion and third party revenue of $903 million from July 1, 2014 to December 31, 2014 included in our consolidated financial statements as of and for the year ended December 31, 2014. The impact of the acquisition of Eagle Rock has not materially affected and is not expected to materially affect our internal control over financial reporting. As a result of these integration activities, certain controls will be evaluated and

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may be changed. We believe, however, that we will be able to maintain sufficient controls over the substantive results of our financial reporting throughout this integration process.
Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2014.2017.
Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2014,2017, as stated in their report, which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners

Board of Directors of LE GP, LLC and
Unitholders of Energy Transfer Equity, L.P.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2014,2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2017, and our report dated February 23, 2018 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. Our audit of,
We are a public accounting firm registered with the PCAOB and opinion on, the Partnership’s internal control over financial reporting does not include the internal control over financial reporting of Susser Holdings Corporation, a consolidated subsidiary, whose financial statements reflect total assets and revenues constituting 4 and 3 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014. Our audit of, and opinion on, the Partnership’s internal control over financial reporting also does not include the internal control over financial reporting of Eagle Rock Energy Partners, L.P.’s midstream business, whose financial statements reflect total assets and revenues constituting 3 and 2 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014. As indicated in Management’s Report on Internal Control over Financial Reporting, Susser Holdings Corporation and Eagle Rock Energy Partners, L.P.’s midstream business were acquired during 2014. Management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of Susser Holdings Corporation and Eagle Rock Energy Partners, L.P.’s midstream business. We did not audit the internal control over financial reporting of Sunoco LP, a consolidated subsidiary, whose financial statements as of December 31, 2014 and for the period from September 1, 2014are required to December 31, 2014 reflect total assets and revenues constituting 3 and 2 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014. Sunoco LP’s internal control over financial reporting was audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to Sunoco LP’s internal control over financial reporting in relationbe independent with respect to the Partnership taken as a whole, is based solely onin accordance with the reportU.S. federal securities laws and the applicable rules and regulations of the other auditors.Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit and the report of the other auditors provideprovides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, based on our audit and the report of the other auditors, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2014, and our report dated March 2, 2015 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Dallas, Texas
March 2, 2015February 23, 2018

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Changes in Internal Controls over Financial Reporting
There has been no change in our internal controls over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three months ended December 31, 20142017 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B.  OTHER INFORMATION
None.

PART III
ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
Our General Partner,general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of ETE are officers and directors of LE GP, LLC. The members of our General Partnergeneral partner elect our General Partner’sgeneral partner’s Board of Directors. The board of directors of our General Partnergeneral partner has the authority to appoint our executive officers, subject to provisions in the limited liability company agreement of our General Partner.general partner. Pursuant to other authority, the board of directors of our General Partnergeneral partner may appoint additional management personnel to assist in the management of our operations and, in the event of the death, resignation or removal of our chief executive officer, to appoint a replacement.
As of December 31, 2014,2017, our Board of Directors was comprised of seven persons, three of whom qualify as “independent” under the NYSE’s corporate governance standards. We have determined that Messrs. Williams, RamseyBrannon, Turner and TurnerWilliams are all “independent” under the NYSE’s corporate governance standards.
As a limited partnership, we are not required by the rules of the NYSE to seek unitholder approval for the election of any of our directors. We believe that the members of our General Partnergeneral partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of the Parent Company, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees, but we believe that the members of our General Partnergeneral partner have endeavored to assemble a group of individuals with the qualities and attributes required to provide effective oversight of the Parent Company.
Risk Oversight
Our Board of Directors generally administers its risk oversight function through the board as a whole. Our President, who reports to the Board of Directors, has day-to-day risk management responsibilities. Our President attends the meetings of our Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Parent Company’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Parent Company’s internal auditor, who reports directly to the Audit Committee, and reviews the Parent Company’s contingencies with management and our independent auditors.
Corporate Governance
The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be provided in print form to any Unitholder requesting such information.
Please note that the preceding Internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found and/or provided at such Internet addresses or at our website in general is intended or deemed to be incorporated by reference herein.
Annual Certification
The Parent Company has filed the required certifications under Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 to this annual report. In 2014,2017, our President and CFO provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate governance listing standards.

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Conflicts Committee
Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the General Partnergeneral partner is fair and reasonable to the Parent Company and our Unitholders. As a policy matter, the Conflicts Committee generally reviews any proposed related-party transaction that may be material to the Parent Company to determine if the transaction presents a conflict of interest and whether the transaction is fair and reasonable to the Parent Company. Pursuant to the terms of our partnership agreement, any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Parent Company, approved by all partners of the Parent Company and not a breach by the General Partnergeneral partner or its Board of Directors of any duties

they may owe the Parent Company or the Unitholders. These duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in Item“Item 1A. Risk FactorsFactors” in this annual report).
Audit Committee
The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board has determined that based on relevant experience, Audit Committee member Matt RamseyRick Turner qualified as an audit committee financial expert during 2014.2017. A description of the qualifications of Mr. RamseyTurner may be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.”
The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our independent auditors matters required to be discussed by auditing standards, and makes recommendations to the Board of Directors relating to our audited financial statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the audited financial statements of ETE be included in ETE’s Annual Report on Form 10-K for the year ended December 31, 2014.2017.
The Board of Directors adopts the charter for the Audit Committee. Matthew S. Ramsey,Richard D. Brannon, K. Rick Turner and William P. Williams serve as elected members of the Audit Committee. Mr. Ramsey currently serves as the Chair of the Audit Committee. Mr. Ramsey currently serves as a member or chairman of the audit committee of three other publicly traded companies, including Sunoco LP, in addition to his service as a member of the Audit Committee of our General Partner. Mr. Turner also serves on the audit committee of three other publicly traded companies, including Sunoco LP. As required by Rule 303A.07 of the NYSE Listed Company Manual, the Board of Directors of our General Partner has determined that such simultaneous service does not impair Mr. Ramsey’s or Mr. Turner’s ability to effectively serve on our Audit Committee.
Compensation and Nominating/Corporate Governance Committees
Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions pertaining to the vesting of any such awards. Pursuant to the Charter of the Compensation Committee, a director serving as a member of the Compensation Committee may not be an officer of or employed by our General Partner,general partner, the Parent Company, ETP or its subsidiaries, or RegencySunoco LP or its subsidiaries. Subsequent to the resignations of Paul E. Glaske and Bill W. Byrne from the board of directors of our General Partner effective June 30, 2011, ETE did not have a compensation committee; therefore, the members of the board of directors of our General Partner who would be eligible to be members of the Compensation Committee served in that capacity. In February 2013, Mr. Ramsey was appointed to the ETE Compensation Committee.

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Matters relating to the nomination of directors or corporate governance matters were addressed to and determined by the full Board of Directors for the period ETE did not have a compensation committee.
In the discussion and analysis that follows, we have used the term, “ETE Compensation Committee,” to refer to either or both of (i) our compensation committee, which existed through June 2011 and from February 2013 to the present, and (ii) the eligible members of the board of directors of our General Partner, functioning in the capacity of our compensation committee subsequent from June 2011 to February 2013.
The responsibilities of the ETE Compensation Committee include, among other duties, the following:
annually review and approve goals and objectives relevant to compensation of our President and CFO, if applicable;
annually evaluate the President and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with respect to the President and CFO’s compensation levels, if applicable, based on this evaluation;
make determinations with respect to the grant of equity-based awards to executive officers under ETE’s equity incentive plans;
periodically evaluate the terms and administration of ETE’s long-term incentive plans to assure that they are structured and administered in a manner consistent with ETE’s goals and objectives;
periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;
periodically evaluate the compensation of the directors;

retain and terminate any compensation consultant to be used to assist in the evaluation of director, President and CFO or executive officer compensation; and
perform other duties as deemed appropriate by the Board of Directors.
The responsibilities of the ETP Compensation Committee include, among other duties, the following:
annually review and approve goals and objectives relevant to compensation of the Chief Executive Officer, or the CEO, if applicable; annually evaluate the CEO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors of ETP with respect to the CEO’s compensation levels based on this evaluation, if applicable;
based on input from, and discussion with, the CEO, make recommendations to the Board of Directors of ETP with respect to non-CEO executive officer compensation, including incentive compensation and compensation under equity based plans;
make determinations with respect to the grant of equity-based awards to executive officers under ETP’s equity incentive plans;
periodically evaluate the terms and administration of ETP’s short-term and long-term incentive plans to assure that they are structured and administered in a manner consistent with ETP’s goals and objectives;
periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;
periodically evaluate the compensation of the directors;
retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO or executive officer compensation; and
perform other duties as deemed appropriate by the Board of Directors of ETP.
Code of Business Conduct and Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are applicable to the principal executive officer, principal financial officer, principal accounting officer and controller, or those persons performing similar functions, of our General Partner.general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may not be posted.
Meetings of Non-management Directors and Communications with Directors
Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings.
We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the Board, any of the independent directors, or any one director serving on the Board of Directors by sending

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written correspondence addressed to the desired person, committee or group to the attention of Sonia Aubé at Energy Transfer Equity, L.P., 3738 Oak Lawn Avenue,8111 Westchester Drive, Suite 600, Dallas, Texas, 75219.75225. Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.
Directors and Executive Officers of Our General Partner
The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our General Partnergeneral partner as of March 2, 2015.February 23, 2018. Executive officers and directors are elected for indefinite terms.
Name Age Position with Our General Partner
John W. McReynolds 6467
 Director and President
Kelcy L. Warren 5962
 Director and Chairman of the Board
Jamie WelchThomas E. Long 4861
Group Chief Financial Officer
Marshall S. (Mackie) McCrea, III58
 Director and Group Chief FinancialOperating Officer and Head of Business DevelopmentChief Commercial Officer
Thomas P. Mason61
Executive Vice President and General Counsel
Brad Whitehurst 4043
 Executive Vice President and Head of Tax
Marshall S. (Mackie) McCrea, IIIRichard D. Brannon 5559
 Director
Matthew S. Ramsey 5962
 Director
K. Rick Turner 5759
 Director
William P. Williams 7780
 Director
Messrs. Warren, Welch and McCrea also serve as directors of ETP’s General Partner. Mr. McReynolds also servesgeneral partner. Messrs. Ramsey and Turner serve as directordirectors of Regency’s General Partner.the general partner of Sunoco LP.
Set forth below is biographical information regarding the foregoing officers and directors of our General Partner:general partner:
John W. McReynolds.  Mr. McReynolds has served as our President since March 2005, and as a Director since August 2005. He served as our Chief Financial Officer from August 2005 to June 2013, and has previously served as a directorDirector of Energy Transfer PartnersETP from August 2001 through May 2010. Mr. McReynolds has also served as a director of Regency since May 2010.been in the energy industry for his entire career. Prior to becoming President and CFO of Energy Transfer Equity,ETE, Mr. McReynolds was a partner with the internationalin private law firm of Hunton & Williams LLPpractice for over 20 years. As a lawyer, Mr. McReynolds specializedyears,  specializing exclusively in energy-related finance, securities, corporations and partnerships, mergers and acquisitions, syndicationsyndications, and litigation matters,a wide variety of energy-related litigation. His practice dealt with all forms of fossil fuels, and served as an expert in special projects for Boardsthe transportation and handling thereof, together with the financing and structuring of Directors for public companies.all forms of business entities related thereto. The members of our General Partnergeneral partner selected Mr. McReynolds to serve as a directorin the indicated roles with the Energy Transfer partnerships because of his legalthis extensive background and his extensive experience, in energy-related corporate finance. Mr. McReynolds has relationships with executives and senior management at several companies in the energy sector, as well as with investment bankers who coverhis many contacts and relationships in the industry.
Kelcy L. Warren.  Mr. Warren was appointed Co-Chairman of the Board of Directors of our General Partner,general partner, LE GP, LLC, effective upon the closing of our IPO. On August 15, 2007, Mr. Warren became the sole Chairman of the Board of our General Partnergeneral partner and

the Chief Executive Officer and Chairman of the Board of the General Partnergeneral partner of ETP. Prior to that, Mr. Warren had served as Co-Chief Executive Officer and Co-Chairman of the Board of the General Partnergeneral partner of ETP since the combination of the midstream and intrastate transportation storage operations of ETC OLP and the retail propane operations of Heritage in January 2004. Mr. Warren also serves as Chief Executive Officer of the General Partnergeneral partner of ETC OLP. Mr. Warren also served as the Chief Executive Officer of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Prior to the combination of the operations of ETP and Heritage Propane, Mr. Warren served as President of the General Partnergeneral partner of ET Company I, Ltd. the entity that operated ETP’s midstream assets before it acquired Aquila, Inc.’s midstream assets, having served in that capacity since 1996. From 1996 to 2000, he also served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a Director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 2530 years of business experience in the energy industry. The members of our General Partnergeneral partner selected Mr. Warren to serve as a director and as Chairman because he is ETP’s Chief Executive Officer and has more than 2530 years in the natural gas industry. Mr. Warren also has relationships with chief executives and other senior management at natural gas transportation companies throughout the United States, and brings a unique and valuable perspective to the Board of Directors.
Jamie Welch. Thomas E. Long.Mr. Welch has served asLong is the Group Chief Financial Officer of ETE since February 2016. Mr. Long also served as the Chief Financial Officer and Headas a director of Business DevelopmentsPennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long has served as a director of Sunoco LP since May 2016. Mr. Long previously served as Chief Financial Officer of ETP and as Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. From May 2008 to November 2010, Mr. Long served as Vice President and Chief Financial Officer of Matrix Service Company. Prior to joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream Partners, LP, a publicly traded natural gas and natural gas liquids midstream business company located in Denver, CO. In that position, he was responsible for all financial aspects of the company since its formation in December 2005. From 1998 to 2005, Mr. Long served in several executive positions with subsidiaries of Duke Energy Corp., one of the nation’s largest electric power companies.
Marshall S. (Mackie) McCrea, III.  Mr. McCrea is the Group Chief Operating Officer and Chief Commercial Officer for the Energy Transfer family and has served in that capacity since November 2015. Mr. McCrea was appointed as a director of the general partner of ETP in December 2009. Prior to that, he served as President and Chief Operating Officer of ETP’s general partner from June 2013.2008 to November 2015 and President – Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President – Commercial Development since January 2004. In March 2005, Mr. WelchMcCrea was named President of La Grange Acquisition LP, ETP’s primary operating subsidiary, after serving as Senior Vice President-Business Development and Producer Services since 1997. Mr. McCrea also currently serves on the Board of Directors of the general partner of ETE. Mr. McCrea also served as the Chairman of the Board of Directors of the general partner of Sunoco Logistics from October 2012 to April 2017. The members of our general partner selected Mr. McCrea to serve as a director because he brings extensive project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.
Thomas P. Mason.Mr. Mason became Executive Vice President and General Counsel of the general partner of ETE in December 2015. Mr. Mason also served as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETP’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining ETP, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also served on the Board of Directors of ETE, ETP, andthe general partner of Sunoco Logistics, since June 2013. Before joining ETE, Mr. Welch was Head of the EMEA Investment Banking Department and Head of the Global Energy Group at Credit Suisse. He was also a member of the IBD Global Management Committee and the EMEA Operating Committee. Mr. Welch joined Credit Suisse First Boston in 1997 from Lehman Brothers Inc. in New York, where he was a Senior Vice President in the global utilities & project finance group. PriorOctober 2012 to that he was an attorney with Milbank, Tweed, Hadley & McCloy (New York) and a barrister and solicitor with Minter Ellison in Melbourne Australia. The members of our General Partner selected Mr. Welch to serve on the Board of Directors because of his understanding of energy-related corporate finance gained through his experience in the investment banking and legal fields.April 2017.

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Brad Whitehurst. Mr. Whitehurst has served as the Executive Vice President and Head of Tax of our General Partnergeneral partner since August 2014. Prior to joining ETE, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised ETE and its subsidiaries in his role as outside counsel since 2006.
Marshall S. (Mackie) McCrea, IIIRichard D. Brannon. .  Mr. McCreaBrannon was appointed as a director on December 23, 2009. He isto the President and Chief Operating OfficerBoard of ETP GP and has servedDirectors of our general partner in that capacity since June 2008. Prior to that, he served as President – Midstream from March 2007 to June 2008.2016. Previously, he served ason the Senior Vice President – Commercial Development since the combinationSunoco LP Board of the operations of ETC OLP and HOLP in January 2004. InDirectors from September 2014 to March 2005,2016. Mr. McCrea was named president of ETC OLP. Prior to the combination of the operations of ETC OLP and HOLP, Mr. McCreaBrannon has also served as the Senior Vice President – Business Development and Producer Services of the general partner of ETC OLP and ET Company I, Ltd., having served in that capacity since 1997. Mr. McCrea also currently serves on the Board of Directors of WildHorse Resource Development Corp. (NYSE: WRD), since its IPO in December 2016 he is CEO of CH4 Energy II, III, IV, V and VI, all independent companies focused on horizontal development of oil and gas. Previously, he was President of CH4 Energy Corp. from 2001 to 2006, when the general partnercompany was sold to Bill Barrett Corp. From 1984 to 2005, Dick was President of ETE,Brannon Oil & Gas, Inc. and Brannon & Murray Drilling Co. Previously, he was a drilling and completion engineer for Texas Oil & Gas Corp. He has previously served on the boards of Sunoco LogisticsCornerstone Natural Gas Corp., which was purchased by El Paso Corp. in 1996, and OEC Compression Corp, acquired by Hanover Compressor Company in 2001. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation committee of Regency, Energy Partners LP and Sunoco LP. The members of our General Partnergeneral partner selected Mr. McCreaBrannon to serve as a director because he bringsof his extensive project developmentenergy industry experience and operations experience to the Board. He has held various positions in the natural gas business over the past 25 yearshis service on other public company boards and is able to assist the Board of Directors in creating and executing the Partnership’s strategic plan.committees.

Matthew S. Ramsey.Ramsey. Mr. Ramsey was appointed as a director of ETE’s general partner on July 17, 2012 and as a director of ETP’s general partner on November 9, 2015. Mr. Ramsey currently serves as chairPresident and Chief Operating Officer of ETP’s general partner since November 2015. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the Audit Committee and a memberboard of the Compensation Committee.directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey is also a director of Sunoco LP, serving as chairchairman of Sunoco LP’s audit committee and serving on Sunoco LP’s compensation committee.board since April 2015. Mr. Ramsey is presentlypreviously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership generating and drilling 3-D seismic prospects on the Gulf Coast of Texas. Mr. Ramsey is also President of Ramsey Energy Management, LLC, the General Partner of Ramsey Energy Partners, I, Ltd.,currently a private oil and gas partnership, and as President of Dollarhide Management, LLC, the General Partner of Deerwood Investments, Ltd., a private oil and gas partnership. Additionally, Mr. Ramsey is President of Gateshead Oil, LLC, a private oil and gas partnership. He also serves as Manager of MSR Energy, LLC, the general partner of Shafter Lake Energy Partners, Ltd., a private oil and gas exploration limited partnership. In 2014, Mr. Ramsey joined the board of directorsdirector of RSP Permian, Inc. (NYSE: RSPP), where he serves as chairman of the compensation committee and as a member of the audit committee. Mr. Ramsey formerly served as President of DDD Energy, Inc. until its sale in 2002. From 1996 to 2000, Mr. Ramsey served as President and Chief Executive Officer of OEC Compression Corporation, Inc., a publicly traded oil field service company, providing gas compression services to a variety of energy clients. Previously, Mr. Ramsey served as Vice President of Nuevo Energy Company, an independent energy company. Additionally, he was employed by Torch Energy Advisors, Inc., a company providing management and operations services to energy companies including Nuevo Energy, last serving as Executive Vice President. Mr. Ramsey joined Torch Energy as Vice President of Land and was named Senior Vice President of Land in 1992. Prior to joining Torch Energy Advisors, Inc., Mr. Ramsey was self employed for eleven years. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate of Harvard Business School Advanced Management Program. Mr. Ramsey is licensed to practice law in the State of Texas. He is qualified to practice in the Western District of Texas and the United States Court of Appeals for the Fifth Circuit. Mr. Ramsey formerly served as a director of Southern Union Company. The membersmember of our General Partnergeneral partner recognize Mr. Ramsey’s vast experience in the oil and gas space and believe that he provides valuable industry insight as a member of our Board of Directors.
K. Rick Turner.  Mr. Turner has served as a director of our General Partnergeneral partner since October 2002. Mr. Turner currently serves as chair of the Compensation Committee and a member of the Audit Committee. Mr. Turner is also a director of Sunoco LP, serving as chair of Sunoco LP’s compensation committee and serving on Sunoco LP’s audit committee.committees. Mr. Turner is presently a managing director of Altos Energy Partners, LLC. Mr. Turner previously was a private equity executive with several groups after retiring from the Stephens’ family entities, which he had worked for since 1983. He first became a private equity principal in 1990 after serving as the Assistant to the Chairman, Jackson T. Stephens. His areas of focus have been oil and gas exploration, natural gas gathering, processing industries, and power technology. Prior to joining Stephens, he was employed by Peat, Marwick, Mitchell and Company. Mr. Turner currently serves as a director of North American EnergyAmeriGas Partners, Inc. and AmeriGas.L.P. Mr. Turner earned his B.S.B.A. from the University of Arkansas and is a non-practicing Certified Public Accountant. The members of our General Partnergeneral partner selected Mr. Turner based on his industry knowledge, his background in corporate finance and accounting, and his experience as a director and audit committee member on the boards of several other companies.
William P. Williams. Mr. Williams was appointed as a director onin March 24, 2012 and currently serves as a member of the Audit Committee. Mr. Williams began his career in the oil and gas industry in 1967 with Texas Power and Light Company as Manager of Pipeline Construction for Bi-Stone Fuel Company, a predecessor of Texas Utilities Fuel Company. In 1980, he was employed by Endevco as Vice President of Pipeline and Plant Construction, Engineering, and Operations. Prior to Endevco, he worked for Cornerstone Natural Gas followed byGas. Mr. Williams later joined Energy Transfer Partners, L.P. as Vice President of Engineering and Operations, at Energy Transfer Partners, L.P. ending his career as Vice President of Measurement onin May 1, 2011. The members of our general partner selected Mr. Williams also serves as a member ofdue to his experience in the Audit Committee.pipeline industry and his familiarity with our business.

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Compensation of the General Partner
Our General Partnergeneral partner does not receive any management fee or other compensation in connection with its management of the Parent Company.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our officers andthe directors and executive officers of our general partner, as well as persons who own more than 10%ten percent of a registered class of our equity securities,the common units representing limited partnership interests in us, to file reports of beneficial ownership and changes in beneficialof ownership on Forms 3, 4 and 5 with the SEC. Officers, directors and greater than 10% Unitholders are required byThe SEC regulations to furnish the General Partner withalso require that copies of allthese Section 16(a) forms.
reports be furnished to us by such reporting persons. Based solely on ourupon a review of the copies of such forms received by us, or written representations from certain reporting persons,these reports, we believe that during the year ended December 31, 2014, all filing requirements applicable to our officers, directors, and greater than 10% beneficial ownersSection 16(a) reports were mettimely filed in a timely manner, with the exception of a late filing of a Form 4 for Mr. Welch.2017.

ITEM 11.  EXECUTIVE COMPENSATION
Overview
As a limited partnership, we are managed by our General Partner. Our General Partner is majority owned by Mr. Kelcy Warren. Our limited partner interests are owned approximately 27% by affiliates and approximately 73% by the public.
We own 100% of ETP GP and its general partner, ETP LLC. We refer to ETP GP and ETP LLC together as the “ETP GP Entities.” ETP GP is the general partner of ETP. All of ETP’s employees receive employee benefits from the operating companies of ETP.
We ownacquired 100% of RegencySunoco GP and its general partner, Regency LLC. We refer to Regency GP LP and Regency GP LLC, together as the “Regency GP Entities.” Regency GP is the general partner of Regency.Sunoco LP, from ETP in July 2015. All of Regency’sSunoco LP’s employees receive employee benefits from either Sunoco GP LLC or the operating companies of Regency.Sunoco LP.
Compensation Discussion and Analysis
Named Executive Officers
We doETE does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of our General Partner perform all of ourETE’s management functions. As a result, the executive officers of our General Partner are essentially ourETE’s executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the total compensation of the executive officers of our General Partner as set forth below. In addition, to provide comprehensive disclosure of our executive compensation, we are also providing information as to the executive compensation of certain executive officers of our subsidiaries, even though none of these persons is an executive officer of the Parent Company. Accordingly, the persons we refer to in this discussion as our “named executive officers” are the following:
ETE Executive Officers
John W. McReynolds, President;
Jamie Welch,Thomas E. Long, Chief Financial Officer and Group Chief Financial Officer of ETE’s general partner;
Marshall S. (Mackie) McCrea, III, Group Chief Operating Officer and Head of Business Development;Chief Commercial Officer;
Thomas P. Mason, Executive Vice President and General Counsel; and
Bradford D. Whitehurst, Executive Vice President and Head of TaxTax.
Certain Subsidiary Executive Officers
Marshall S. (Mackie) McCrea, III, ETP President and Chief Operating Officer; and
Michael J. Bradley, Regency’s President and Chief Executive Officer
During 2014, Messrs. McCrea and Bradley’s primary business responsibilities were undertaken for ETP and Regency, respectively. The compensation committees of the general partners of ETP and Regency, respectively, sets the components of Messrs. McCrea and Bradley’s compensation, including base salary, long-term incentive awards and annual bonus utilizing the same philosophy and methodology adopted by our General Partner.

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Our Philosophy for Compensation of Executives
Our General Partner. In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for the named executive officers that provides for a slightly below the median market annual base compensation rate (i.e. approximately the 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short and long-term performance that are both targeted to pay-out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by the payment of annual discretionary cash bonuses and grants of restricted unit awards. Our General Partner believes the performance of our operating subsidiaries and the contribution of our management toward the achievement of the financial targets and other goals of those subsidiaries should be considered in determining annual discretionary cash bonuses.
ETP GP Entities. The ETP GP Entities also believe that a significant portion of each executives’ compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be very competitive in the marketplace for executive talents and abilities. ETP GP seeks a total compensation program for the named executive officers that provides for a slightly below the median market annual base compensation rate (i.e. approximately the 40th percentile of market) but incentive-based compensation composed of a combination of compensation vehicles to reward both short and long-term performance that are both targeted to pay-out at approximately the top-quartile of market. ETP GP believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider the achievement of ETP’s financial performance objectives for a fiscal year set at the beginning of such fiscal year and the individual contributions of its named executive officers to the success of ETP and the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit or phantom unit awards under ETE’s equity incentive plan, ETP’s equity incentive plan(s), or the equity incentive programs of Sunoco LP, as applicable based on the allocation of the named executive officers’ award, which awards are intended to provide a longer term incentive and retention value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution ETP paysand/or the other affiliated partnerships pay to its Unitholders.their respective unitholders.
Prior to December 2012, ETP’s equity awards were primarily in the form of
The Partnership grants restricted unit awards that vest over a specified time period, with substantially all of these types of unit awards vesting over a five-year period at 20% per year generally based on continued employment through each specified vesting date. Beginning in December 2012, we began granting restrictedunit/phantom unit awards that vest, based generally upon continued employment, at a rate of 60% after the third year of service and the remaining 40% after the fifth year of service. The ETP GP Entities believe that these equity-based incentive arrangements are important in attracting and retaining executive officers and key employees as well as motivating these individuals to achieve ETP’sstated business objectives. The equity-based compensation reflects the importance ETP GP places on aligning the interests of its named executive officers with those of ETP’s Unitholders.unitholders.
While ETE, through the ETP GP Entities and/or the Regency GP Entities, is responsible for the direct payment of the compensation of our named executive officers, ETE does not participate or have any input in any decisions as to the compensation levels or policies of our General Partner the ETP GP Entities or the RegencyETP GP Entities. As discussed below, our compensation committee, the eligible members of board of directors of our General Partner at times when we have not had a compensation committee or the ETP Compensation Committee the Regency Compensation Committee and/or the compensation committee of the general partner of Sunoco Logistics and Sunoco LP, as applicable, all in consultation with the General Partner, are responsible for the compensation policies and compensation level of the named executive officers of our General Partner. In this discussion, we refer to either or both of our compensation committeethe ETE Compensation Committee or such members of our board of directors collectively as the “ETE Compensation Committee.”
ETP also does not participate or have any input in any decisions as to the compensation policies of the ETP GP Entities or the compensation levels of the executive officers of the ETP GP Entities. The compensation committee of the board of directors of the ETP GP Entities (the “ETP Compensation Committee”) is responsible for the approval of the compensation policies and the compensation levels of the executive officers of the ETP GP Entities.
RegencySunoco LP also does not participate or have any input in any decisions as to the compensation policies of the RegencySunoco GP EntitiesLLC or the compensation levels of the executive officers of the Regency GP Entities.its general partner. The compensation committee of the board of directors of the Regency GP Entities (the “RegencySUN Compensation Committee”) in consultation with the General Partner, as appropriate,Committee is responsible for the approval of the compensation policies and the compensation levels of the executive officers of the RegencySunoco GP Entities.LLC.
ETE and ETP directly pay their respective executive officers in lieu of receiving an allocation of overhead related to executive compensation from their respective general partner. For the year ended December 31, 2014, ETE and ETP paid 100% of the compensation of the executive officers of their respective general partner as each entity represents the only business currently managed by such general partner.

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For a more detailed description of the compensation to ETE’s and ETP GP’s named executive officers, please see “– Compensation Tables” below.
Distributions to Our General Partner
Our General Partner is partially-owned by certain of our current and prior named executive officers. We pay quarterly distributions to our General Partner in accordance with our partnership agreement with respect to its ownership of its general partner interest as specified in our partnership agreement. The amount of each quarterly distribution that we must pay to our General Partner is based solely on the provisions of our partnership agreement, which agreement specifies the amount of cash we distribute to our General Partner based on the amount of cash that we distribute to our limited partners each quarter. Accordingly, the cash distributions we make to our General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General Partner are described in detail in Note 98 to our consolidated financial statements. Our named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per unit distributions equal the per unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named executive officers.officers or the services they perform as employees.
For a more detailed description of the compensation of our named executive officers, please see “Compensation Tables” below.
Compensation Philosophy
Each of ETE’s and ETP’sOur compensation programs are structured to provideachieve the following benefits:following:
reward executives with an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities yielding a total compensation package approaching the top-quartile of the market;
attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other executive officers and key management employees employed by publicly traded limited partnerships of similar size and in similar lines of business;
motivate executive officers and key employees to achieve strong financial and operational performance;
emphasize performance-based or “at-risk” compensation; and
reward individual performance.

Components of Executive Compensation
For the year ended December 31, 2014,2017, the compensation paid to ETE’s and ETP GP’sour named executive officers consisted of the following components:
annual base salary;
non-equity incentive plan compensation consisting solely of discretionary cash bonuses;
time-vested restrictedrestricted/phantom unit awards under the equity incentive plan(s);
payment of distribution equivalent rights (“DERs”) on unvested time-based restricted unit award under our equity incentive plan;
vesting of previously issued time-based restricted unit/phantom restricted unit awards issued pursuant to our equity incentive plans;
plans or the equity incentive plans(s) of affiliates; and
401(k) plan compensation.
Mr. Warren, the Chairman of the Board of ETE and the CEO of ETP GP, has voluntarily elected not to accept any salary, bonus or equity incentive compensation (other than a salary of $1.00 per year plus an amount sufficient to cover his allocated employee premium contributions for health and welfare benefits).employer contributions.
Methodology
Presently, the compensation committees ofThe ETE ETP, Regency and their subsidiaries and affiliates, as applicable, considerCompensation Committee considers relevant data available to themit to assess theour competitive position with respect to base salary, annual short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The boards of directors and compensation committees of ETE ETP, Regency and their subsidiaries, as applicable,Compensation Committee also considerconsiders individual performance, levels of responsibility, skills and experience.
Periodically, the compensation committees of ETE or ETP and/or its affiliates engageCompensation Committee engages a third-party consultant to provide market information for compensation levels at peer companies in order to assist the compensation committees in the determination of

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compensation levels for our executive officers, including the named executive officers. Most recently, Longnecker & Associates (“Longnecker”) evaluated the market competitiveness of total compensation levels of a number of officers of ETE and ETP Compensation Committee engaged Mercer (US) Inc. (“Mercer”)to provide market information with respect to compensation of those executives during the year ended December 31, 20132017. In particular, the review by Longnecker was designed to both (i) evaluate the market competitiveness of total compensation levels for certain members of senior management, including itsour named executive officers; (ii) assist in the determination of appropriate compensation levels for itsour senior management, including the named executive officers; and (iii) to confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy. This review by Mercer was deemed necessary given the series of transforming transactions ETE and its affiliates have completed over the past few years, which have significantly increased the size and scale of ETE and its affiliates from both a financial and asset perspective.
In conducting its review, Mercer worked withLongnecker specifically considered the larger size of the combined ETE and ETP to identify aentities from an energy industry perspective. During 2017, Longnecker assisted in the development of the final “peer group” of 15 leading companies in the energy industry that most closely reflect ETE’sthe profile of ETP and ETP’s profileETE in terms of revenues, assets and market value as well as compete with ETE and ETPcompetition for talent at the senior management level.level and similarly situated general industry companies with similar revenues, assets and market value. In setting such peer group, the size of ETE and ETP on a combined basis was considered. Unlike in prior evaluations conducted by Longnecker, a determination was made to focus the analysis specifically on the energy industry based on a determination that an energy industry peer group provided a more than sufficient amount of comparative data to consider and evaluate total compensation. This decision allowed Longnecker to report on specific industry related data comparing the levels of annual base salary, annual short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive officers of these other companies. The identified companies were:
Energy Peer Group:
• Conoco Phillips • Anadarko Petroleum Corporation
• Enterprise Products Partners, L.P. • ONEOK Partners, L.P.Marathon Petroleum Corporation
• Plains All American Pipeline, L.P. • EOG Resources,Kinder Morgan, Inc.
• Halliburton Company• Kinder Morgan Energy Partners, L.P.
• National Oilwell Varco, Inc. • The Williams Companies, Inc.
• Baker Hughes IncorporatedValero Energy Corporation • Enbridge Energy Partners, L.P.
• Apache Corp.• DCP Midstream Partners, L.P.
• Marathon Oil CorporationPhillips 66
The compensation analysis provided by MercerLongnecker in 2017 covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term incentive awards for the senior executives of these companies. TheIn preparing the review materials, Longnecker utilized generally accepted compensation principles as determined by WorldatWork and gathered data from the public peer companies and published salary surveys.

Following Longnecker’s 2017 review, the ETE Compensation Committees of ETE and ETP utilizedCommittee reviewed the information provided, by Mercer to compare the levels of annual base salary, annual short-term cash bonusincluding Longnecker’s specific conclusions and long-term equity incentive awards at these other companies with those of its named executive officers to ensure thatrecommended considerations for all compensation of our named executive officers is both consistent with our compensation philosophy and competitive with the compensation for executive officers of these other companies.going forward. The ETE Compensation Committee also considered and reviewed the results of the study performed by MercerLongnecker to ensuredetermine if the results indicated that ourthe compensation programs were yielding a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance objectives. The Compensation Committee also specifically evaluated benchmarked results for the annual base salary, annual short-term cash bonus or long-term equity incentive awards of the named executive officers to compensation levels at the identified “peer group” companies. Mercer did not provide any non-executive compensation services forobjectives and considered Longnecker’s conclusions and recommendations. While Longnecker found that ETE or ETP during 2013. In additionis achieving its stated objectives with respect to the information received“at-risk” approach, they also found that certain adjustments should be implemented to allow ETE to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term) as a result of a periodic engagement of a third party consultant, the Compensation Committee also utilizes information obtained from other sources, such as annual third-party surveys, for comparison purposes in its determination of compensation levels for our named executive officers.
Mercer did not provide any additional executive compensation services for the Compensation Committee during 2014. For 2014, the Compensation Committee continued to use the results of the 2013 Mercer compensation analysis, adjusted to account for general inflation and 2014 third-party survey results.described below.
Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers, and compensates them for their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the named executive officers are reviewed on an annual basis. As discussed above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e. approximately the 40th percentile of market) and are determined by the ETE Compensation Committee after taking into account the recommendationrecommendations of Mr. Warren. The
During the 2017 merit review process, the ETE Compensation Committee did not increase the base salaries of Messrs. McReynolds or Welch for 2014. Mr. Whitehurst’s base salary of $475,000 was set by his employment offer letter from ETE dated June 26, 2014.
The base salaries of ETP’s and Regency’s named executive officers are determined by the respective compensation committees of ETP and Regency, which take into accountconsidered the recommendations of Mr. Warren, the respective CEOs of ETP and Regency. For 2014, the ETP Compensation Committee did not increase Mr. McCrea’s annual base salary becauseresults of the base salary adjustment made in 2013 in accordance with the MercerLongnecker study and the Regencymerit increase pool set for all employees of ETP GP and ETP. The ETE Compensation Committee approved an increase to the base salary of 3% for Mr. Bradley’sMcReynolds of 2.5% to $598,026 from its prior level of $583,440; a 2.5% base salary. The Regencysalary increase of Mr. McCrea to $1,045,000 from its prior level of $1,020,000; and a 2.5% base salary increase to Mr. Mason to $592,276 from its prior level of $577,830. In the case of Mr. Long, the ETE Compensation Committee determined that theapproved an increase in to Mr. Bradley’sLong’s base salary to $530,000 from its prior level of $459,000, which represents an approximately 15.5% increase and was warranted in lightbased largely on the recommendation of Mr. Warren and the results of the increasedLongnecker study. In the case of Mr. Whitehurst, the ETE Compensation Committee approved an increase to Mr. Whitehurst’s base salary to $525,000 from its prior level of responsibility related$508,725, which represents an approximately 3.2% increase and was based largely on the recommendation of Mr. Warren and the results of the Longnecker study.
The 2.5% increase to managementMessrs. McReynolds, McCrea and Mason reflected a base salary increase consistent with the 2.5% annual merit increase pool set for all employees of Regency afterETE and its 2014 acquisitions.affiliates for 2017 approved by the respective compensation committees.
Annual Bonus.  For 2014, the ETE Compensation Committee approved short-term annual cash bonus targets for Messrs. McReynolds and Welch of 125% of their annual base salary, which targets were the same as their targets for 2013. Mr. Whitehurst’s

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short-term annual cash bonus target was set at 120% in accordance with the terms of his employment offer letter from ETE dated June 26, 2014.
In February 2015, the ETE Compensation Committee approved a cash bonus relating to the 2014 calendar year to Messrs. McReynolds and Welch in the amounts of $687,500 and $687,500, respectively. In approving this cash bonus, the ETE Compensation Committee took into account the significant role that Mr. McReynolds has as the senior management person for ETE with respect to managing the business of ETE, as well as his role in providing strategic advice related to multiple other transactions among ETE and its subsidiaries. The ETE Compensation Committee also took into account the individual performance of Messrs. McReynolds and Whitehurst with respect to promoting ETE’s financial, strategic and operating objectives for 2014. In the case of Mr. Welch for 2014, his bonus amount was based on factors consistent with those utilized for Mr. McReynolds as well as those utilized by the ETP Compensation Committee in considering an award to the Mr. McCrea and the Regency Compensation Committee in considering an award to Mr. Bradley. With respect to Mr. Whitehurst, his bonus amount was based on the term of his original offer letter of June 26, 2014, which provided for a bonus guarantee of $570,000 for 2014. Moving forward, Mr. Whitehurst’s future bonus awards will be based on factors consistent with those utilized for Messrs. McReynolds and Welch as well as those utilized by the ETP Compensation Committee and Regency Compensation Committee in considering awards.
In addition to base salary, the respective compensation committees of ETP and Regency makeETE Compensation Committee makes determinations whether to awardmake discretionary annual cash bonus awards to executives, including our named executive officers, discretionary annual cash bonuses following the end of the year. year under the Energy Transfer Partners, L.L.C. Annual Bonus Plan (the “Bonus Plan”).
These discretionary bonuses, if awarded, are intended to reward theour named executive officers for the achievement of financial performance objectives during the year for which the bonuses are awarded in light of the contribution of each individual to the entity’sour profitability and success during such year. In previous years, the respective compensation committees of ETP and Regency have taken into account whether ETP or Regency, respectively, achieved or exceeded their targeted performance objectives for the year, which are approved by the board of directors of the respective general partner as discussed below, as an important element in making its determinations with respect to annual bonuses. The respective compensation committees of ETP and RegencyETE Compensation Committee also considerconsiders the recommendation of the respective CEOs of ETP and Regency as well as any input from the General Partnerour Chairman in determining the specific annual cash bonus amounts for each of the other named executive officers. The respective compensation committees of ETP and Regency doETE Compensation Committee does not establish theirits own financial performance objectives in advance for purposes of determining whether to approve any annual bonuses, and the respective compensation committees of ETP and Regency doit does not utilize any formulaic approach to determiningdetermine annual bonuses.
In 2014, the board of directors of the general partners of TheETP and Regency, upon recommendation of the respective compensation committees, approved the Energy Transfer Partners, L.L.C. Annual Bonus Plan and the Regency GP LLC Annual Bonus Plan (collectively the “New Bonus Plans”), which replaced the prior bonus plans (the “Prior Bonus Plans”). The New Bonus Plans, which became effective for calendar year 2014, are substantially similar to the Prior Bonus Plans, except that the New Bonus plan includes an additional performance criteria related to ETP and Regency’s internal department financial budget, respectively, in addition to the previous performance measure of an internal earnings target generally based on targeted EBITDA (the “Earnings Target”) budget. Under the New Bonus Plan, the Compensation Committee’s evaluation of performance and determination of an overall available bonus pool is based on therespective partnership’s Earnings Targetinternal earnings target generally based on targeted EBITDA (the “Earnings Target”) budget and the performance of each department compared to the applicable departmental budget (with suchperformance measured based on the specific dollar amount of general and administrative expenses set for each department). The two performance criteria are weighted 75% on theinternal Earnings Target budget criteria and 25% on internal department financialbudget criteria.
In adopting the New Bonus Plan, the board of directors and the compensation committees of the ETP GP Entities and the Regency GP Entities have reaffirmed the internal Internal Earnings Target asis the primary performance factor in determining annual bonuses. The addition of thebonuses, while internal department financial budget criteria is designedconsidered to ensure that the partnerships arePartnership is effectively managing general and administrative costs in a prudent manner.
For 2017, the ETE Compensation Committee approved short-term annual cash bonus pool targets for Messrs. McReynolds, Long, Mason and Whitehurst of 130% of their annual base earnings and a bonus pool target of 160% for Mr. McCrea. The 130% target for Mr. Whitehurst represents an increase from his previous target of 125% and represents a desire on the part of the Chairman to align the senior officers that report to him, other than Mr. McCrea, with a consistent bonus target. The targets of the other named executive officers were consistent with the prior year’s targets.
In February 2018, the ETP and Regency’s internal financial budgets are generally developed for each business segment, and then aggregated with appropriate corporate level adjustments to reflect an overallCompensation Committee certified 2017 performance objective that is reasonableresults under the Bonus Plan, which resulted in lighta bonus payout of market conditions and opportunities based on a high level100% of effort and dedication across all segmentstarget, which reflected achievement of ETP and Regency’s businesses. The evaluation101.6% of ETP and Regency’s performances versus their internal financial budget is based on the internal Earnings Target forand 100% of the budget criteria. Based on the approved results, the ETE Compensation Committee approved a cash bonus relating to the 2017 calendar year. year to Messrs. McReynolds, Long, McCrea, Mason and Whitehurst in the amounts of $764,306, $625,100, $1,644,554, $756,958, and $667,852, respectively.

In general,approving the respective compensation committees for ETP and Regency believe that performance at or above their internal Earnings Target would support2017 bonuses toof the named executive officers, ranging from 100% to 125% and 75% to 120% of their annual bonus target, respectively. For 2014, ETP’sthe ETE Compensation Committee retainedtook into account the same short-term annual cash bonus target for Mr. McCrea from 2013, 140%achievement by the respective partnerships of his annual base salary and Regency’s Compensation Committee set a short-term annual cash bonus target for Mr. Bradley of 125% of his annual base salary. The increase in targets for Mr. Bradley reflected the desire to account for the increase in the sizeall of the Regency organization during 2014targeted performance objectives for 2017 and normalization of his target with other similarly situated executives within ETE’s affiliated partnerships. The individual bonus amounts for each named executive officer, also reflect the respective compensation committees’ view of the impact of such individual’s efforts and contributions towards (i) achievement of the partnership’s success in exceeding its internal financial budget, (ii) the development of new projects that are

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expected to result in increased cash flows from operations in future years, (iii) the completion of mergers, acquisitions or similar transactions that are expected to be accretive to the partnership and increase distributable cash flow, (iv) the overall management of the partnership’s business, and (v) the individual performances of these individuals with respect to promotingeach of the partnership’s financial, strategic and operating objectives for 2014.named executive officers, as well as the study results of Longnecker. The cash bonuses awarded to each of the executive officers for 20142017 performance were consistent with the target. In respect of 2014 performance, in February 2015, ETP’s Compensation Committee approved a cashtheir applicable bonus relating to the 2014 calendar year to Mr. McCrea of $1,120,000 and the Regency Compensation Committee approved a cash bonus relating to the 2014 calendar year to Mr. Bradley of $773,921.pool targets.
ETE Equity Awards.  TheIn 2017, ETE adopted the Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan (“(the “ETE Plan”). The ETE Plan”)Plan authorizes the ETE Compensation Committee, in its discretion, to grant awards of restricted units, phantom units, unit options, unit appreciation rights and other awards related to ETE common units at such times and upon such terms and conditions as it may determine appropriate and in accordance with each such plan. Thegeneral guidelines as defined by the ETE Compensation Committee determined and/or approved the terms of the unit grants awarded to the named executive officers of ETE, including the number of ETE Common Units subject to the unit awardPlan. For 2015 and the vesting structure of those unit awards. All of the awards granted to the named executive officers under this equity2016, no long-term incentive plan have consisted of restricted unit awards that are subject to vesting over a specified time period. ETE Common Units are issued upon grant of the award, subject to forfeiture of unvested units upon termination of employment during the vesting period. For 2014, no equity awards were issued under the Energy Transfer Equity Long-Term IncentiveETE Plan. The
For 2017, the annual long-term incentive targets set by the ETE Compensation Committee for the named executive officers were 500% of annual base salary for Mr. Long, 900% of annual base salary for Mr. McCrea, 500% of annual base salary for Mr. Mason and 400% of base salary for Mr. Whitehurst, which were consistent with the prior year’s targets.
In December 2017, the ETE Compensation Committee in consultation with ETE’s Chairman determined to issue long-term incentive awards under the ETE Plan to the ETE named executive officers, other than Mr. McReynolds, who does not currently receive equity awards on an annual basis, each participated under long-term incentive plans of ETP, Regency and/or Sunoco Logistics, as applicable.
Messrs. Welch and Whitehurst are eligible on an annual basis to receive annual long-term incentive awards under the Second Amended and Restated Energy Transfer Partners, L.P 2008 Long-Term Incentive Plan (the “2008 Incentive Plan”) or the long-term incentive plans of ETE’s affiliates, including the Regency GP LLC Long-Term Incentive Plan date February 3, 2006 (the “Regency Plan”) and the Sunoco Partners LLC Long-Term Incentive Plan (the “Sunoco Logistics Plan”). For 2014, ETE’s Compensation Committee set Mr. Welch’s long-term incentive award target at 400% of his base salary and Mr. Whitehurst’s target at 400% of his base salary, which amountawards. This determination was an increase from the 300% originally provided for in his employment offer letter. This increase was driven by Mr. Whitehurst’s assumption of additional responsibilities beyond the group tax function for which he was hired. As described below in the section titled Affiliate/Subsidiary Equity Awards, for 2014, in discussions between the General Partner and the compensation committees of the general partners of ETP, Regency and Sunoco Logistics, it was determined that for 2014 the value of Messrs. Welch and Whitehurst’s awards would be comprised of restricted/phantom unit awards under the 2008 Incentive Plan, the Regency Plan and Sunoco Logisticsmade in consideration of their roles and responsibilities for all of the partnerships under ETE’s umbrella and, for Mr. Welch, as a member of the Boards of Directors of the general partners of ETP and Sunoco Logistics. Each of the unit awards provide for vesting over a five-year period, with 60% at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date and entitle Mr. Welch to receive DERs on the unvested units. For Messrs. Welch and Whitehurst, their total 2014 long-term incentive awards were allocated 1/3 to the 2008 Incentive Plan, 1/3 to the Sunoco Logistics Plan and 1/3 to the Regency Plan. It is expected that the long-term equity awards of the named executive officers of ETE will recognize a similar aggregation of restricted units. The terms and conditions of the restricted unit awards to Messrs. Welch and Whitehurst under the 2008 Incentive Plan, the Sunoco Logistics Plan and the Regency Plan were the same and provided for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the awards would be accelerated in the event of their death, disability or upon a change in control. Additionally, as described below in the section titled Affiliate/Subsidiary Equity Awards, the awards to Mr. Whitehurst provided for an acceleration upon a termination without “cause”.
Mr. Whitehurst also received additional long-term incentive awards under each of the 2008 Incentive Plan, the Sunoco Logistic Plan and the Regency Plan in accordance with the terms of his employment offer letter dated June 26, 2014. The offer letter provided that Mr. Whitehurst, upon commencement of employment, would receive a one-time equity award having a total grant date value of $4,750,000 (the “Initial Award”), which value was intended to reflect (i) an amount equal to three (3) years of targeted long-term incentive award value and (ii) a grant value equal to 100% of his initial annual base salary. The Initial Award, as in the case of Mr. Whitehurst’s 2014 awards, was divided pro-rata between the 2008 Incentive Plan, the Sunoco Logistics Plan and the Regency Plan, resulting in an award of 28,203 units under the 2008 Incentive Plan related to ETP common units, 51,794 restricted phantom units under the Regency Plan related to Regency common units and 35,445 time-based restricted units under the Sunoco Logistics Plan related to Sunoco Logistics common units. The unit awards in accordance with the Initial Award provide for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. The vesting of the Initial Award would be accelerated under each applicable equity award plan in the event of (i) Mr. Whitehurst’s death, (ii) Mr. Whitehurst’s disability; (iii) upon a change in control; or (iv) upon a termination of Mr. Whitehurts’s employment without “cause”. The Initial Award is described more fully below in the section titled Affiliate/Subsidiary Equity Awards.

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ETP Equity Awards.  Each of ETP’s 2004 Unit Plan and 2008 Incentive Plan authorizes the ETP Compensation Committee, in its discretion, to grant awards of restricted units, unit options and other awards related to ETP common units at such times and upon such terms and conditions as it may determine in accordance with each such plan. The ETP Compensation Committee determined and/or approved the terms of the unit grants awarded to the named executive officers of the ETP GP Entities, includinglimiting the number of units issued under the ETP common units subject to the unit award and the vesting structure of those unit awards. All of the awards granted to ETP’s named executive officers under these equity incentive plans have consisted of restricted unit awards that are subject to vesting over a specified time period. Upon vesting of any unit award, ETP common units are issued. For 2014, Mr. McCrea’s long-term incentive target increased from 700% of his annual base salary to 750% of his base salary.
for 2017. In December 2014,of 2017, the ETPETE Compensation Committee approved grants of phantom unit awards to Mr.Messrs. Long, McCrea, Mason and Whitehurst of 62,650 ETP common121,074 units, under the 2008 Incentive Plan. These unit awards provide for vesting over a five-year period, with 60% vesting at the end of the third year537,379 units, 135,300 units and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. As described below in the section titled Affiliate/Subsidiary Equity Awards, for 2014, in discussions between the ETP Compensation Committee the compensation committee of the general partner of Sunoco Logistics, it was determined that approximately 33% of the total long-term incentive award target values for Mr. McCrea would be composed of restricted95,945 units, awarded under the Sunoco Logistics Plan in consideration of his roles and responsibilities at Sunoco Logistics in addition to ETP. At Sunoco Logistics, Mr. McCrea serves as Chairman of the Board of Sunoco Logistics’ general partner. It is expected that the long-term equity awards of Mr. McCrea will recognize a similar aggregation of awards being awarded under the 2008 Incentive Plan and the Sunoco Logistics Plan in future years. The terms and conditions of the restricted unit awards to Mr. McCrea under the Sunoco Logistics Plan are identical to the terms and conditions of the restricted unit awards under ETP’s equity incentive plan to Mr. McCrea.respectively.
The restrictedphantom unit awards provide for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, generally subject to continued employment through each specified vesting date. The phantom unit awards entitle the recipients of the phantom unit awards to receive, with respect to each ETP commonETE unit subject to such award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by ETPETE to its Unitholders.unitholders. In approving the grant of such phantom unit awards, the ETPETE Compensation Committee took into account the sameconsidered several factors, as discussed above under the caption “Annual Bonus,”including the long-term objective of retaining such individuals as key drivers of the Partner’sETE’s and ETP’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity unit awards subject to vesting. Vesting of the 20142017 awards would accelerate in the event of the death or disability of the named executive officer or in the event of a change in control of ETPETE as that term is defined under the 2008 IncentiveETE Plan.
The issuanceUpon vesting of the phantom units awarded under the ETE Plan, the ETE Compensation Committee reserves the right to determine if, upon vesting, such phantom units shall be settled in (i) common units of ETE (subject to the approval of the ETE Plan prior to the first vesting date by a majority of ETE’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ETE Plan) of the ETE common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property (including, without limitation, delivery of common units of ETP purchased by ETE in the open market) in an amount equal to the Fair Market Value of ETE common units that would otherwise be delivered pursuant to ETP’s equitythe terms of the grant agreement, or a combination thereof as determined by the ETE Compensation Committee in its discretion.
From time to time, the compensation committees of ETP and/or Sunoco LP may make grants under the respective long-term incentive plans is intended to serveemployees and/or directors containing such terms as a means of incentive compensation; therefore, no considerationthe respective compensation committee shall determine. The applicable compensation committee determines the conditions upon which the restricted units or restricted phantom units granted may become vested or forfeited, and whether or not any such restricted units or restricted phantom units will be payablehave distribution equivalent rights (“DERs”) entitling the grantee to distributions receive an amount in cash equal to cash distributions made by the plan participants upon vesting and issuancerespective partnership with respect to a like number of partnership common units during the restricted period. For 2017, there were no awards made to the named executive officers under an ETP long-term incentive plan.
In December of 2017, consistent with ETE’s compensation methodology, all of the ETP common units.
The restricted unit awardsunits and restricted phantom units granted under the ETP equitylong-term incentive plans generally requireof ETE, ETP and Sunoco LP, including to the named executive officers, provided for vesting of 60% at the end of the third year and vesting of the remaining 40% at the end of the fifth year, subject to continued employment of the recipient duringnamed executive officers through each specified vesting date. The restricted units and restricted phantom unit awards entitle the vesting period, provided however,grantee of the unvestedunit awards will be acceleratedto receive, with respect to each partnership common unit subject to such restricted unit or restricted phantom unit award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution to the partnership unitholders. In approving the grant of such unit awards, the applicable compensation committee took into account a number of performance factors as well as the long-term objective of retaining such individuals as key drivers of the partnership’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2017 awards would accelerate in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. In addition,named executive officer or in the event of a change in control of the respective partnership all unvested awards grantedas that term is defined under the 2004 Unit Plan, as well asapplicable long-term incentive plan.

As described below in the section titled Affiliate/Subsidiary Equity Awards, for 2017, in discussions between the General Partner, the ETE Compensation Committees and the compensation committees of the general partners of ETP and Sunoco, it was determined that for 2017 the value of Messrs. Long, Mason and Whitehurst’s awards granted in 2014would be comprised of restricted/phantom unit awards under the 2008ETE Plan and the Sunoco LP 2012 Long-Term Incentive Plan would be accelerated. For awards previously granted under the 2008(the “2012 Incentive Plan prior to December 2014, unvested awards may also become vested upon a changePlan”) in control at the discretionconsideration of their roles and responsibilities for all of the Compensation Committee.partnerships under ETE’s umbrella and, for Messrs. Long and Mason, as members of the Boards of Directors of the general partner of Sunoco. Messrs. Long, Mason and Whitehurst’s total 2017 long-term awards were allocated 80% to the ETE Plan and 20% to the 2012 Incentive Plan. Mr. McCrea’s 2017 long-term incentive award was allocated entirely to the ETE Plan. It is expected that future long-term incentive awards to the named executive officers of ETE will recognize an aggregation of restricted/phantom restricted units under long-term incentive plans of ETE, ETP and/or Sunoco LP, as applicable.
The ETP and SUN Compensation Committee hasCommittees have in the past and may in the future, but isare not required to, accelerate the vesting of unvested restricted unit awards in the event of the termination or retirement of an executive officer. The ETP Compensation Committee did not accelerateNone of the compensation committees accelerated the vesting of restricted unit awards to any ETE named executive officers in 2014.2017.
As discussed below under “Potential Payments Upon a Termination or Change of Control,” certain equity awards automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the 2014 awards to Mr.Messrs. McCrea and Mr. Whitehurst included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause”. For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliate.

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We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control and the acceleration of vesting awards upon a termination without “cause” in the case of the 2014 unit awards to Mr. McCrea and Mr. Whitehurst creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities.
Regency Equity Awards.Each of the Regency GP LLC Long-Term Incentive Plan dated February 3, 2006 (the “Regency 2006 Plan”) and the Regency Energy Partners LP 2011 Long-Term Incentive Plan (the “Regency 2011 Plan”) authorizes the Regency Compensation Committee, in its discretion, to grant awards of phantom units, common units, restricted units, unit options and other unit-based awards to employees, directors and consultants of the Partnership and its affiliates and subsidiaries. The Regency Compensation Committee determined and/or approved the terms of the unit grants awarded to our named executive officers, including the number of phantom units subject to the unit award and the vesting structure of those unit awards. All of the awards granted to the named executive officers under these equity incentive plans have consisted of phantom unit awards that are subject to vesting over a specified time period. Upon vesting of any unit award, Regency Common Units are issued.
In December 2014, the Compensation Committee approved grants of time-based phantom unit awards under the 2011 Plan to Mr. Bradley of 83,800 Regency Common Units. These phantom unit awards provide for vesting in Regency Common Units of 60% at the end of the third year and vesting of the remaining 40% at the end of the fifth year, subject to continued employment through each specified vesting date. These phantom unit awards entitle the recipients of the unit awards to receive, with respect to each Regency Common Unit subject to such phantom unit award that has not either vested or been forfeited, a DER cash payment promptly following each such distribution by us to our unitholders. In approving the grant of such unit awards, the Regency Compensation Committee took into account the same factors as discussed above under the caption “Annual Cash Bonus,” the long-term objective of retaining such individuals as key drivers of the Partnership’s future success, the existing level of equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting.
The issuance of phantom units pursuant to our equity incentive plans is intended to serve as a means of incentive compensation; therefore, no consideration will be payable by the plan participants upon vesting and issuance of the Regency Common Units.
The phantom unit awards under the Regency equity incentive plans generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. In addition, in the event of a change in control of the partnership, all unvested awards granted under the Regency 2006 Plan, as well as awards granted in 2014 under the 2008 Incentive Plan, would be accelerated. For awards granted under the 2011 Regency Plan prior to December 2014, unvested awards may also become vested upon a change in control at the discretion of the Compensation Committee.
The Regency Compensation Committee has in the past and may in the future, but is not required to, accelerate the vesting of unvested restricted unit awards in the event of the termination or retirement of an executive officer. The Regency Compensation Committee did not accelerate the vesting of restricted unit awards to any named executive officers in 2014.
As discussed below under “Potential Payments Upon a Termination or Change of Control,” certain equity awards automatically accelerate upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In addition, the 2014 award to Mr. Bradley included a provision in the applicable award agreement for acceleration of unvested restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause”. For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliate.affiliates.
We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling employees to realize value from these awards in the event that we undergo a change in control transaction. In addition, we believe permitting acceleration of vesting upon a change in control and the acceleration of vesting awards upon a termination without “cause” in the case of the 2014 unit awardawards to Mr. BradleyMessrs. McCrea and Whitehurst creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment and encourage these officers to remain focused on their job responsibilities.

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ETE Unit Ownership Guidelines. In December 2013, the Board of Directors of our General Partner adopted the ETE Executive Unit Ownership Guidelines (the “Guidelines”), which set forth minimum ownership guidelines applicable to certain executives of ETE with respect to ETE Common Units representing limited partnership interests in ETE. The applicable unit ownership guidelines are denominated as a multiple of base salary, and the amount of ETE Common Units required to be owned increases with the level of responsibility. Under these guidelines, Mr. McReynolds as ETE’s President is expected to own ETE Common Units having a minimum value of five times his base salary; Messrs. Welch and Whitehurst are expected to own ETE Common Units having a minimum value of four times their base salary. In addition to the named executive officers, the Guidelines also apply to other covered executives, which are expected to own either directly or indirectly in accordance with the terms of the Guidelines ETE Common Units having minimum values ranging from two to four times their respective base salaries.
The ETE Compensation Committee believes that the ownership of ETE Common Units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to ETE’s total unitholder return, aligning the interests of such executives with those of ETE’s Unitholders, and promoting ETE’s interest in good corporate governance.
Covered executives are generally required to achieve their ownership level within five years of becoming subject to the guidelines; however, certain covered executives, based on their tenure as an executive, are required to achieve compliance within two years of the December 2013 effective date of the Guidelines. Thus, compliance with the guidelines will be required for Mr. McReynolds beginning in December 2015, for Mr. Welch in December 2018 and for Mr. Whitehurst in August 2019.
Covered executives may satisfy the guidelines through direct ownership of ETE Common Units or indirect ownership by certain immediate family members. Direct or indirect ownership of ETE Common Units shall count on a one to one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements.
Executive officers who have not yet met their respective guideline must retain and hold all ETE Common Units (less ETE Common Units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required ETE Common Units must be maintained for as long as the covered executive is subject to the guidelines. However, those individuals who have met or exceeded their applicable ownership guideline may dispose of the ETE Common Units in a manner consistent with applicable laws, rules and regulations, including regulations of the SEC and ETE’s internal policies, but only to the extent that such individual’s remaining ownership of ETE Common Units would continue to exceed the applicable ownership guideline.
The Board of Directors of ETP and Regency’s general partners approved and adopted policies substantially identical to the Guidelines described above. Under the ETP guidelines, Mr. McCrea, the President and Chief Operating Officer of ETP, is expected to own ETP common units having a minimum value of five times his base salary. Under the Regency guidelines, Mr. Bradley, as CEO of Regency, is expected to own Regency common units having a minimum value of five times his base salary.
Affiliate and Subsidiary Equity Awards. In addition to their roles as officers of our General Partner during 2017, Messrs. WelchLong, McCrea, Mason and Whitehurst in their roles have certain responsibilities for all of the partnerships under ETE’s umbrella, including with respect to Mr. Welch,McCrea as a member of the Boards of Directors of the general partners of ETP and with respect to Mr. Long, as Chief Financial Officer of ETP and a member of the Board of Directors of the general partner of Sunoco Logistics. In connection with those roles at ETP, the ETPLP.
The SUN Compensation Committee in December 2017 approved grants of unitunits awards to Messrs. WelchLong, Mason and Whitehurst of 11,50017,097, 19,106 and 9,90013,548 units, respectively under the 20082012 Incentive Plan related to ETPSunoco LP common units. The Regency Compensation Committee awarded Messrs. Welch and Whitehurst restricted phantom units in the amount of 24,500 and 21,000 respectively. The Sunoco Logistics’ Compensation Committee awarded Messrs. Welch and Whitehurst time-based restricted units of Sunoco Logistics in the amount of 15,117 units and 13,060 units, respectively. The terms and conditions of the restricted unit/phantom awards to Messrs. WelchLong, Mason and Whitehurst under the 20082012 Incentive Plan, the Sunoco Logistics Plan the Regency Planas applicable, were the same and provided for vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40% vesting at the end of the fifth year, subject generally to continued employment through each specified vesting date. All of the awards would be accelerated in the event of their death, disability or upon a change in control. Additionally,
Unit Ownership Guidelines. In December 2013, the awardsBoard of Directors of our General Partner adopted the Executive Unit Ownership Guidelines (the “Guidelines”), which set forth minimum ownership guidelines applicable to Mr. Whitehurst included a provision in thecertain executives of ETE and ETP with respect to ETE, ETP and Sunoco LP common units representing limited partnership interests, as applicable. The applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause”. For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere pleaGuidelines are denominated as a conviction)multiple of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliate.

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In connection with his role at Sunoco Logistics, in December 2014, Sunoco Logistics’ Compensation Committee awarded Mr. McCrea time-based restricted units of Sunoco Logistics inbase salary, and the amount of 41,136 time-based restrictedcommon units underrequired to be owned increases with the Sunoco Logistics Plan. Thelevel of responsibility. Under these Guidelines, Mr. McReynolds as ETE’s President and Mr. McCrea as Group Chief Operations Officer and Chief Commercial Officer are expected to own common units having a minimum value of five times their base salaries and Messrs. Long, Mason and Whitehurst are expected to own common units having a minimum value of four times their base salaries. In addition to the named executive officers, the Guidelines also apply to other executives, all of whom are expected to own either directly or indirectly in accordance with the terms and conditions of the restrictedGuidelines, common units having minimum values ranging from two to four times their respective base salaries.
The ETE Compensation Committee believes that the ownership of ETE, ETP and/or Sunoco LP common units, as reflected in these Guidelines, is an important means of tying the financial risks and rewards for its executives to ETE’s total unitholder return,

aligning the interests of such executives with those of ETE’s Unitholders, and promoting ETE’s interest in good corporate governance.
Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines; however, certain covered executives, based on their tenure as an executive, are required to achieve compliance within two years of the December 2013 effective date of the Guidelines. Thus, compliance with the Guidelines was required for Messrs. McReynolds, McCrea and Mason beginning in December 2015, and they were compliant. Compliance for Mr. Long will be required in December 2018, and compliance for Mr. Whitehurst will be required in December 2019.
Covered executives may satisfy the Guidelines through direct ownership of ETE, ETP and/or Sunoco LP common units or indirect ownership by certain immediate family members. Direct or indirect ownership of ETE, ETP and/or Sunoco LP common units shall count on a one-to-one ratio for purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to Mr. McCrea undersatisfy the Sunoco Logistics areminimum ownership requirements.
Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner consistent with applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining ownership of common units would continue to exceed the applicable ownership level.
The Board of Directors of ETP’s general partner approved and adopted policies substantially identical to the terms and conditions of the 2014 unit awards under the 2008 Incentive Plan.Guidelines described above.
Qualified Retirement Plan Benefits.  The Energy Transfer Partners GP, L.P. 401(k) Plan (the “ETP 401(k) Plan”) is a defined contribution 401(k) plan, which covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of covered compensation. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement. This profit sharing contribution was previously included in the Sunoco sponsored 401(k) which was merged with the ETP 401(k) Plan effective January 1, 2014.
Beginning in January 2013, theThe Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service.
Health and Welfare Benefits.  All full-time employees, including our ETP’s and Regency’s named executive officers may participate in ETP GP’s health and welfare benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance.
Termination Benefits. ETE’s, ETP’s and Regency’s Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or that provide for any payments in the event of a change in control of our General Partner. ETP’s 2004 UnitIn addition, ETE Plan, Second Amended and Regency’s 2006 UnitRestated Energy Transfers Partners, L.P. 2008 Long-Term Incentive Plan (the “2008 Incentive Plan”), the Energy Transfer Partners, L.P. Amended and Restated 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”), and the Energy Transfer Partners, L.L.C. Long Term Incentive Plan, as amended and restated (the “ETP Plan”) provide the ETP Compensation Committee with the discretion, unless otherwise specified in the applicable award agreement, to provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change inof control, as defined in the plans.plan; (ii) death or (iii) disability, as defined in the applicable plan. In the case of the December 2014 and 2015 long-term incentive awards to the named executive officers under ETP’s 2008 Incentive Plan, the ETP Plan or the Sunoco LogisticsLP 2012 Long-Term Incentive Plan and Regency Plan,(the “2012 Incentive Plan”), the awards would immediately and fully vest all unvested restricted unit awards in the event of a change inof control, as defined in the applicable plan. In addition the December 2014 awards to Messrs. McCrea, Bradley and Whitehurst under the 2008 Incentive Plan, the Regency Plan and/or the Sunoco Logistics Plan provide for acceleration in the event of termination without cause. In addition, ETP’s 2008 Incentive Plan and Regency’s 2001 Plan provide the respective compensation committees with the discretion to provide for acceleration in the event of termination without cause.
Additionally, in connection with Mr. Welch joining ETE as Group Chief Financial Officer and Head of Business Development effective as of April 29, 2013, ETE agreed to award Mr. Welch 1,500,000 Common Units of ETE (after adjustment for the January 2014 two-for-one split), subject to a period of restriction, under the ETE Plan pursuant to a Unit Award Under Long-Term Incentive Plan and the Time-Vested Restricted Unit Award Agreement, each dated as of April 29, 2013 (the “Original Award Agreements”). On December 23, 2013, ETE and Mr. Welch entered into (i) a Rescission Agreement in order to rescind the original offer letter to the extent it relates to the award of 1,500,000 Common Units of ETE (after adjustment for the January 2014 two-for-one split) to Welch, the Original Award Agreements, and the receipt of cash amounts by Mr. Welch with respect to such awarded units and (ii) a new Class D Unit Agreement between ETE and Mr. Welch (the “Class D Unit Agreement”) providing for the issuance to Mr. Welch of an aggregate of 1,540,000 Class D Units of ETE (after unit split adjustment), which number of Class D Units includes an additional 40,000 Class D Units that were issued to Mr. Welch in connection with other changes to his original offer letter.
Under the terms of the Class D Unit Agreement, 30% of the Class D Units granted to Mr. Welch will convert to ETE Common Units on a one-for-one basis on March 31, 2015, and the remaining 70% will convert to ETE Common Units on a one-for-one basis on March 31, 2018, subject in each case to Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and there being a sufficient amount of gain available to be allocated to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date. Upon a Change of Control (as defined in the Class D Unit Agreement), Termination without Cause or for Good Reason (as defined in the Class D Unit Agreement) or upon death or disability, all of the Class D Units issued to Mr. Welch will convert to ETE Common Units subject again to the availability of a sufficient amount of allocable gain and the requirement of Good Standing will cease to apply.
Please refer to “– Compensation“Compensation Tables –- Potential Payments Upon a Termination or Change of Control” for additional information.
In addition, ETP GP has also adopted the ETP GP Severance Plan and Summary Plan Description effective as of June 12, 2013, (the “Severance Plan”), which provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two weeks or one year of annual base salary (with a

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minimum of four weeks of annual base salary) and up to three months of continued group health insurance coverage. The Severance Plan also provides that we ETP or Regency may determine to pay benefits in addition to those provided under the Severance Plan based on special circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried

employees on a nondiscriminatory basis; therefore, amounts that would be payable to ETE’s, ETP’s and/or Regency’sour named executive officers upon a Qualified Termination have been excluded from “Compensation Tables – Potential Payments Upon a Termination or Change of Control” below.
ETP Non-Qualified Deferred Compensation Plan.  ETE does not have a deferred compensation plan. Our subsidiaries maintains (the “ETP NQDC Plan”) is a deferred compensation plan, (“DC Plan”), which permits eligible highly compensated ETP and Regency employees to defer a portion of their salary, bonus, and/or bonusquarterly non-vested phantom unit distribution equivalent income until retirement, or termination of employment or other designated distribution. Underdistribution event. Each year under the DCETP NQDC Plan, each year eligible ETP and Regency employees are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution income, and/or 50% of their discretionary performance bonus compensation to be earned for services performed during the following year. Pursuant to the DCETP NQDC Plan, ETP and Regency may make annual discretionary matching contributions to participants’ accounts; however, neither ETP nor Regency has not made any discretionary contributions to participants’ accounts nor do theyand currently havehas no plans to make any discretionary contributions to participants’ accounts. All amounts credited under the DCETP NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed earnings (or losses)or losses based on hypothetical investment fund choices made by the participants among available funds.
Participants may elect to have their accountsaccount balances distributed in one lump sum payment or in annual installments over a period of three or five years upon retirement, and in a lump sum upon other termination.termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the DCETP NQDC Plan) DCof ETP, all ETP NQDC Plan accounts are immediately vested in full. However, distributions are not accelerated and, instead, are made in accordance with the DCETP NQDC Plan’s normal distribution provisions unless a participant has elected to receive a change of control distributionsdistribution pursuant to his deferral agreement. None of our named executive officers currently participate in this plan.
Risk Assessment Related to our Compensation Structure.  We believe that the compensation plans and programs for our named executive officers, of ETE and ETP, as well as our other employees, are appropriately structured and are not reasonably likely to result in material risk to ETE or ETP.us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm theour value of ETE, ETP, or Regency or reward poor judgment. We also believe ETE, ETP and Regencywe have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, ETE, ETP and Regencywe generally do not adjust base annual salaries for executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of a portion of our operations. ETE, ETP and RegencyOur subsidiaries generally determine whether, and to what extent, their respective named executive officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named executive officers to the Partnership’s success. ETE, ETPWe and Regencyour subsidiaries use restricted units and phantom units rather than unit options for equity awards because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or keep, options “in-the-money.” Finally, the time-based vesting over five years for ETE’s, ETP’s and Regency’sour long-term incentive awards ensures that the interests of employees align with those of the respectiveour unitholders of ETE, ETP and Regencyour subsidiaries’ unitholders for theour long-term performance of ETE, ETP and Regency.performance.
Tax and Accounting Implications of Equity-Based Compensation Arrangements
Deductibility of Executive Compensation
We are a limited partnership and not a corporation for U.S.United States federal income tax purposes. Therefore, we believe that the compensation paid to the named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully deductible for U.S.United States federal income tax purposes.
Accounting for Unit-Based Compensation
For unit-based compensation arrangements we record compensation expense over the vesting period of the awards, as discussed further in Note 109 to our consolidated financial statements.
Compensation Committee Interlocks and Insider Participation
Messrs.Mr. Turner and RamseyMr. Richard D. Brannon are the only members of the Compensation Committee. During 2014,2017, no member of the Compensation Committee was an officer or employee of us or any of our subsidiaries or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, neither Mr. Turner nor Mr. RamseyRichard D. Brannon is a former employee of ours or any of our subsidiaries.

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Report of Compensation Committee
The board of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the management of ETE. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included in this annual report on Form 10-K.

The Compensation Committee of the
Board of Directors of LE GP, LLC,
general partner of Energy Transfer Equity, L.P.

K. Rick Turner
Matthew S. RamseyRichard D. Brannon
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.

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Compensation Tables
Summary Compensation Table
Name and Principal Position Year 
Salary
($)
 
Bonus
($) (1)
 
Equity
Awards
($) (2)
 
Option
Awards
($)
 
Non-Equity
Incentive Plan
Compensation
($)
 
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings
($)
 
All Other
Compensation
($) (3)
 
Total
($)
 Year 
Salary
($)
 
Bonus (1)
($)
 
Equity
Awards (2)
($)
 
Option
Awards
($)
 
Non-Equity
Incentive Plan
Compensation
($)
 
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
 
All Other
Compensation (3)
($)
 
Total
($)
ETE Officers:                                
John W. McReynolds 2014 $550,000
 $687,500
 $—
 $—
 $—
 $—
 $9,565
 $1,247,065
 2017 $587,928
 $764,306
 $—
 $—
 $—
 $—
 $15,179
 $1,367,413
President 2013 560,577
 700,721
 —
 —
 —
 —
 13,856
 1,275,154
 2016 577,280
 712,922
 —
 —
 —
 —
 10,768
 1,300,970
2012 550,000
 522,500
 —
 —
 —
 —
 13,834
 1,086,334
 2015 560,154
 700,893
 —
 —
 —
 —
 11,103
 1,272,150
Jamie Welch 2014 550,000
 687,500
 2,434,757
 —
 —
 7,765
 13,360
 3,693,382
Group Chief Financial Officer and Head of Business Development 2013 272,885
 550,000
 44,427,760
 —
 —
 —
 180
 45,250,825
                
Thomas E. Long 2017 480,846
 625,100
 2,519,954
 —
 —
 —
 18,320
 3,644,220
Group Chief Financial Officer 2016 454,154
 560,865
 2,007,697
 —
 —
 —
 14,679
 3,037,395
2015 399,207
 480,296
 1,447,063
 —
 —
 —
 14,282
 2,340,848
Marshall S. (Mackie) McCrea, III 2017 1,027,846
 1,644,554
 9,033,341
 —
 —
 —
 16,834
 11,722,575
Group Chief Operating Officer and Chief Commercial Officer 2016 1,009,231
 1,533,990
 8,059,413
 —
 —
 —
 14,818
 10,617,452
2015 840,385
 1,294,192
 6,646,354
 —
 —
 —
 14,282
 8,795,213
Thomas P. Mason 2017 582,275
 756,958
 2,816,048
       18,618
 4,173,899
Executive Vice President and General Counsel 2016 571,729
 706,067
 2,524,064
       14,818
 3,816,678
2015 557,615
 6,300,000
 2,253,927
 —
 —
 —
 14,282
 9,125,824
Brad Whitehurst 2014 184,519
 570,000
 6,489,787
 —
 —
 —
 63,492
 7,307,798
 2017 513,733
 667,852
 1,996,921
       14,275
 3,192,781
Executive Vice President and Head of Tax                 2016 503,354
 597,717
 1,777,758
       14,816
 2,893,645
                 2015 485,962
 584,673
 1,587,514
 —
 —
 —
 37,947
 2,696,096
Certain Subsidiary Executive Officers:  
Marshall S. (Mackie) McCrea, III 2014 800,000
 1,120,000
 5,829,111
 —
 —
 —
 14,072
 7,763,183
President and Chief Operating Officer of ETP 2013 772,115
 1,080,961
 6,715,336
 —
 —
 —
 13,323
 8,581,735
2012 690,000
 700,000
 1,510,985
 —
 —
 —
 12,802
 2,913,787
Michael J. Bradley 2014 619,137
 773,921
 1,969,300
 —
 —
 —
 14,584
 3,376,942
President 2013 612,523
 735,028
 1,943,248
 —
 —
 —
 13,901
 3,304,700
2012 592,250
 600,000
 1,054,000
 —
 —
 —
 41,322
 2,287,572
(1) 
The discretionary cash bonus amounts forearned named executive officers for 20142017 reflect cash bonuses approved by the ETE and ETP Compensation Committees in February 20152018 that are expected to be paid inon or before March 2015.15, 2018.
(2) 
Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB ASC Topic 718. See Note 109 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards.
(3) 
The amounts reflected for 20142017 in this column include (i) matching contributions to the ETP 401(k) planPlan made by ETE on behalf of the named executive officers of $7,981, $13,000$9,024 for Mr. McReynolds and $9,135$13,500 for each Messrs. McReynolds, WelchLong, McCrea, Mason and Whitehurst, respectively, and (ii) contributions to the 401(k) plan made by ETP on behalf of the named executive officer of $13,000 for Mr. McCrea, (iii) contributions to the 401(k) plan made by Regency on behalf of the named executive officer of $13,000 for Mr. Bradley, (iv) the dollar value of life insurance premiums paid for the benefit of the named executive officers. VestingThe amounts reflected for all periods exclude distribution payments in 401(k) contributions occurs immediatelyconnection with distribution equivalent rights on unvested unit awards, because the dollar value of such distributions are factored into the grant date fair value reported in the “Unit Awards” column of the Summary Compensation Table at the time that the unit awards and (v) $54,255 in relocation costs for Mr. Whitehurst.distribution equivalent

131rights were originally granted. For 2017, distribution payments in connection with distribution equivalent rights totaled $423,809 for Mr. Long, $1,928,181 for Mr. McCrea, $680,261 for Mr. Mason and $526,388 for Mr. Whitehurst.
Table of Contents

Grants of Plan-Based Awards Table
Name Grant Date 
All Other Unit Awards: Number of Units
(#) (1)
 
All Other Option Awards: Number of Securities Underlying Options
(#)
 
Exercise or Base Price of Option Awards
($ / Unit)
 
Grant Date Fair Value of Unit Awards
(2)
ETE Officers:          
ETP Unit Awards:          
Jamie Welch 12/16/2014 11,500
 —
 —
 $706,790
Brad Whitehurst 12/16/2014 9,900
 —
 —
 608,454
  8/1/2014 28,203
 —
 —
 1,583,316
Regency Unit Awards:          
Jamie Welch 12/16/2014 24,500
 —
 —
 587,020
Brad Whitehurst 12/16/2014 21,000
 —
 —
 503,160
  8/1/2014 51,794
 —
 —
 1,583,343
Sunoco Logistics Unit Awards:          
Jamie Welch 12/5/2014 15,117
 —
 —
 727,128
  1/29/2014 10,900
 —
 —
 413,819
Brad Whitehurst 12/5/2014 13,060
 —
 —
 628,186
  8/1/2014 35,445
 —
 —
 1,583,328
Certain Subsidiary Executive Officers:          
ETP Unit Awards:          
Marshall S. (Mackie) McCrea, III 12/16/2014 62,650
 —
 —
 3,850,469
Regency Unit Awards:          
Michael J. Bradley 12/19/2014 83,800
 —
 —
 1,969,300
Sunoco Logistics Unit Awards:          
Marshall S. (Mackie) McCrea, III 12/5/2014 41,136
 —
 —
 1,978,642
Name Grant Date 
All Other Unit Awards: Number of Units
(#)
 
All Other Option Awards: Number of Securities Underlying Options
(#)
 
Exercise or Base Price of Option Awards
($ / Unit)
 
Grant Date Fair Value of Unit Awards (1)
ETE Unit Awards:          
Thomas E. Long 12/20/2017 121,074
 —
 $—
 $2,035,254
Marshal S. (Mackie) McCrea, III 12/20/2017 537,379
 —
 —
 9,033,341
Thomas P. Mason 12/20/2017 135,300
 —
 —
 2,274,393
Bradford D. Whitehurst 12/20/2017 95,945
 —
 —
 1,612,835
Sunoco LP Unit Awards:          
Thomas E. Long 12/21/2017 17,097
 —
 —
 484,700
Thomas P. Mason 12/21/2017 19,106
 —
 —
 541,655
Bradford D. Whitehurst 12/21/2017 13,548
 —
 —
 384,086
(1)
Sunoco Logistics Unit amounts reflect the two-for-one split of Sunoco Logistics Common Units in June 2014.
(2) 
We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 109 to our consolidated financial statements.
Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table
A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, nonqualified deferred compensation earnings (and losses), and 401(k) plan contributions can be found in the compensation discussionCompensation Discussion and analysisAnalysis that precedes these tables.

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Outstanding Equity Awards at 2017 Fiscal Year-End Table
Name 
Grant Date
(1)
 Unit Awards
Equity Incentive Plan Awards: Number of Units That Have Not Vested/Converted
(#) (1) (2)
 
Equity Incentive Plan Awards: Market or Payout Value of Units That Have Not Vested/Converted
($) (3)
ETE Officers:      
ETE Unit Awards:      
John W. McReynolds 2/24/2011 20,000
 $1,147,600
Class D Units:      
Jamie Welch 12/23/2013 1,540,000
 88,365,200
ETP Unit Awards:      
Jamie Welch 12/16/2014 11,500
 747,500
  12/30/2013 6,900
 448,500
Brad Whitehurst 12/16/2014 9,900
 643,500
  8/1/2014 28,203
 1,833,195
Regency Unit Awards:      
Jamie Welch 12/16/2014 24,500
 588,000
  1/3/2014 15,000
 360,000
Brad Whitehurst 12/16/2014 21,000
 504,000
  8/1/2014 51,794
 1,243,056
Sunoco Logistics Unit Awards:      
Jamie Welch 12/5/2014 15,117
 631,588
  1/29/2014 10,900
 455,402
Brad Whitehurst 12/5/2014 13,060
 545,647
  8/1/2014 35,445
 1,480,892
Certain Subsidiary Executive Officers:      
ETP Unit Awards:      
Marshall S. (Mackie) McCrea, III 12/16/2014 62,650
 4,072,250
  12/30/2013 69,375
 4,509,375
  1/10/2013 33,333
 2,166,645
  12/20/2011 20,000
 1,300,000
  5/2/2011 27,200
 1,768,000
  1/14/2011 50,000
 3,250,000
Regency Unit Awards:      
Michael J. Bradley 12/19/2014 83,800
 2,011,200
  1/3/2014 74,971
 1,799,304
  12/17/2012 50,000
 1,200,000
  12/21/2011 20,000
 480,000
  12/17/2010 10,000
 240,000
  11/22/2010 10,000
 240,000
Sunoco Logistics Unit Awards:      
Marshall S. (Mackie) McCrea, III 12/5/2014 41,136
 1,718,662
  12/5/2013 54,600
 2,281,188
  1/24/2013 19,998
 835,516
Name 
Grant Date
(2)
 
Unit Awards (1)
Number of Units That Have Not Vested
(#)
 
Market or Payout Value of Units That Have Not Vested
($) (3)
ETE Unit Awards:      
Thomas E. Long 12/20/2017 121,074
 2,089,737
Marshal S. (Mackie) McCrea, III 12/20/2017 537,379
 9,275,162
Thomas P. Mason 12/20/2017 135,300
 2,335,278
Bradford D. Whitehurst 12/20/2017 95,945
 1,656,011
ETP Unit Awards:      
Thomas E. Long 12/29/2016 59,053
 1,058,229
  12/9/2015 27,788
 497,952
  12/4/2015 11,208
 200,847
  12/16/2014 8,192
 146,792
  12/5/2013 6,516
 116,767
       
Marshal S. (Mackie) McCrea, III 12/29/2016 336,386
 6,028,028
  12/9/2015 185,261
 3,319,868
  12/4/2015 93,390
 1,673,549
  12/16/2014 37,590
 673,613
  12/5/2014 16,454
 294,863
  12/30/2013 41,625
 745,920
  12/3/2013 21,840
 391,373
Thomas P. Mason 12/29/2016 79,384
 1,422,552
  12/9/2015 43,733
 783,686
  12/4/2015 22,046
 395,064
  12/16/2014 12,963
 232,297
  12/5/2014 6,047
 108,362
  12/30/2013 24,554
 440,004
Bradford D. Whitehurst 12/29/2016 55,913
 1,001,952
  12/9/2015 30,803
 551,981
  12/4/2015 15,528
 278,262
  12/16/2014 11,138
 199,584
  12/5/2014 5,224
 93,614
  8/1/2014 26,995
 483,751
  12/30/2013 16,922
 303,239
Sunoco LP Unit Awards:      
Thomas E. Long 12/21/2017 17,097
 485,555
  12/29/2016 22,210
 630,764
  12/16/2015 14,125
 401,150
Thomas P. Mason 12/21/2017 19,106
 542,610
  12/29/2016 23,300
 661,720
  12/16/2015 18,523
 526,053
Bradford D. Whitehurst 12/21/2017 13,548
 384,763
  12/29/2016 16,410
 466,044
  12/16/2015 13,046
 370,506
(1) 
In connection with the April 28, 2017 merger between ETP and Sunoco Logistics, each outstanding unvested ETP restricted unit converted into 1.5 units of Sunoco Logistics, maintaining the same terms as the original ETP award. In connection with the merger, Sunoco Logistics changed its name to Energy Transfer Partners, L.P. Certain of these outstanding awards represent ETP awards that converted into Sunoco Logistics awards in connection with the merger.
(2)
ETE phantom unit awards outstanding to Mr. McReynolds vest at a rate of 60% in December of each year through 20152020 and 40% in December 2022 for awards granted in 2011. Class D UnitDecember 2017. Such awards outstanding to Mr. Welch are eligible for conversion may be settledat a ratethe election of 30% in March 2015 and 70% in March 2018, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocated to the Class D Units being converted so as to cause the capital accountCompensation Committee in (i) common units of each such unit to equal the capital account

ETE (subject to the approval of the ETE Plan prior to the first vesting date by a majority of ETE’s unitholders pursuant to the rules of the New York Stock Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the ETE Plan) of the ETE common units that would otherwise be delivered pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property (including, without limitation, delivery of common units of an ETE Common Unit on the conversion date. ETP purchased by ETE in the open market) in an amount equal to the Fair Market Value of ETE common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as determined by the ETE Compensation Committee in its discretion.
ETP and Sunoco LP common unit awards outstanding to Messrs. Welch, Whitehurst and McCrea vest as follows:
at a rate of 60% in December 2017 and 40% in December 2019 for awards granted in December 2014;

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at a rate of 60% in December 2016 and 40% in December 2018 for awards granted in December 2013; and
at a rate of 60% in December 2015 and 40% in December 2017 for awards granted in January 2013.
Regency common unit awards outstanding to Messrs. Welch, Whitehurst and Bradley vest at as follows:
at a rate of 60% in December 2016 and 40% in December 2018 for awards granted in January 2014;
at a rate of 60% in December 2017 and 40% in December 2019 for awards granted in December 2014;
at a rate of 60% in December 2015 and 405 in December 2017 for awards granted in December 2012;
ratably on each anniversary of the grant date through 2016 for awards granted in 2011; and
ratably on each anniversary of the grant date through 2015 for awards granted in 2010.
Sunoco Logistics common unit awards outstanding to Messrs. Welch, Whitehurst and McCrea vest as follows:
at a rate of 60% in December 20172019 and 40% in December 20192021 for awards granted in December 2014;2016;
at a rate of 60% in December 20162018 and 40% in December 20182020 for awards granted in December 2013; and2015;
ratably100% in December 2019 for the remaining outstanding portion of each year through 2017 for awards granted in January 2013.December 2014; and
(2)
100% in December 2018 for the remaining outstanding portion of all other awards.
ETE Unit amounts reflect the two-for-one split of ETE Common Units in January 2014 and Sunoco Logistics unit amounts reflect a two-for-one split of Sunoco Logistics common units in June 2014.
(3) 
Market value was computed as the number of unvested awards (or units not converted in the case of Class D Units) as of December 31, 20142017 multiplied by the closing price of ETP’srespective common units orof ETE, ETP and Sunoco Logistics’ common units, accordingly, for ETP officers and ETE’s Common Units or Regency’s common units, accordingly, for ETE officers on December 31, 2014.
LP.
Option Exercises and Units Vested Table
  Unit Awards
Name 
Number of Units
Acquired on Vesting
(#) (1)
 
Value Realized on Vesting
($) (1)
ETE Officers:    
ETE Unit Awards:    
John W. McReynolds 22,000
 $1,157,480
Class D Units:    
Jamie Welch —
 —
Certain Subsidiary Executive Officers:    
ETP Unit Awards:    
Marshall S. (Mackie) McCrea, III 91,200
 6,007,526
Sunoco Logistics Unit Awards:    
Marshall S. (Mackie) McCrea, III 6,668
 320,331
Regency Unit Awards:    
Michael J. Bradley 30,000
 838,600
  Unit Awards
Name 
Number of Units
Acquired on Vesting
(#)
 
Value Realized on Vesting
($) (1)
ETP Unit Awards:    
Thomas E. Long 18,471
 301,576
Marshall S. (Mackie) McCrea, III 107,732
 1,758,957
Thomas P. Mason 46,513
 759,418
Bradford D. Whitehurst 24,540
 400,665
 
(1) 
ETE Unit amounts reflect the two-for-one split of ETE Common Units in January 2014. Amounts presented represent the number of unit awards vested during 2014 and the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the applicable closing market price of ETP common units Sunoco Logistics common units, Regency Common Units or ETE Common Units, accordingly,for ETP upon the vesting date.
(2)
Sunoco Logistics unit amounts reflect the two-for-one split of Sunoco Logistics common units in June 2014.
We have not issued option awards.

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Nonqualified Deferred Compensation Table
Name 
Executive Contributions in Last FY(1)
($)
 
Registrant Contributions in Last FY
($)
 
Aggregate Earnings in
Last FY(1)
($)
 
Aggregate Withdrawals/Distributions
($)
 
Aggregate Balance at Last FYE(1)
($)
ETE Officers:          
John W. McReynolds $—
 $—
 $—
 $—
 $—
Jamie Welch 275,000
 —
 7,765
 —
 282,765
Brad Whitehurst —
 —
 —
 —
 —
Certain Subsidiary Executive Officers:          
Marshall S. (Mackie) McCrea, III —
 —
 —
 —
 —
Michael J. Bradley —
 —
 —
 —
 —
(1)
The executive contributions and aggregate earnings reflected above for Mr. Welch are included in total compensation in the “Summary Compensation Table”; the remainder of the aggregate balance at last fiscal year end was reported as compensation in previous fiscal years.
A description of the key provisions of the Partnership’s non-qualified deferred compensation plan can be found in the compensation discussion and analysis above. None of the named executive officers participated in the plan in 2017.
Potential Payments Upon a Termination or Change of Control
Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards granted pursuant the ETE Plan will automatically become vested upon a change of control, which is generally defined as the occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting securities of ETE or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the general partner of ETE; or (iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of ETE in one or more transactions to anyone other than an affiliate of ETE.
In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards under the equity incentive plans of ETE ETP and Regency,its affiliated partnerships, generally require the continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or disability of the award recipient prior to the applicable vesting period being satisfied. In addition,All awards granted in 2015, 2016 and 2017 under the ETE Plan, the 2008 Incentive Plan, the 2011 Incentive Plan, the ETP Plan and the 2012 Incentive Plan would be accelerated in the event of a change in control of the partnership, all unvested awards granted under the 2004 Unit Plan and the Regency 2006 Plan, as well as awards granted in 2014 under the 2008 Incentive Plan, the Regency 2011 Plan and the Sunoco Logistics Plan would be accelerated. For awards granted under the 2008 Incentive Plan prior to December 2014, unvested awards may also become vested upon a change in control at the discretion of the applicable compensation committee. This discussion assumes a scenario in which the ETP Compensation Committee and/or the Regency Compensation Committee does not exercise their discretion to accelerate unvested awards in connection with a change in control.Partnership.
The 2014 awards to Messrs. McCrea Bradley and Whitehurst, whether awarded under the 2008 Incentive Plan, the 2011 RegencyIncentive Plan or the Sunoco Logistic Plan included a provision in the applicable award agreement for acceleration of unvested restricted unit/restricted phantom unit awards upon a termination of employment by the general partner of the applicable partnership issuing the award without “cause”.“cause.” For purposes of the awards the term “cause” shall mean: (i) a conviction (treating a nolo contendere plea

as a conviction) of a felony (whether or not any right to appeal has been or may be exercised), (ii) willful refusal without proper cause to perform duties (other than any such refusal resulting from incapacity due to physical or mental impairment), (iii) misappropriation, embezzlement or reckless or willful destruction of property of the partnership or any of its affiliates, (iv) knowing breach of any statutory or common law duty of loyalty to the partnership or any of its or their affiliates, (v) improper conduct materially prejudicial to the business of the partnership or any of its or their affiliates, by, (vi) material breach of the provisions of any agreement regarding confidential information entered into with the partnership or any of its or their affiliates or (vii) the continuing failure or refusal to satisfactorily perform essential duties to the partnership or any of its or their affiliate.affiliates.
The Class D Unit Agreement between ETE and Mr. Welch contains change of control provisions that are similar to those in the ETE Plan. Thus, under the terms of the Class D Unit Agreement, the Class D Units will convert to ETE Common Units and the requirement of Good Standing will cease to exist upon the occurrence of one or more of the change of control events described above. In addition, the termsETE Compensation Committee, the ETP Compensation Committees and the compensation committee of the Class D Unitegeneral partner of Sunoco LP, have approved a retirement provision, which provides that employees, including the named executive officers with at least ten years of service with the general partner, who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The Sunoco Logistics Compensation Committee beginning with awards made in December 2014 have included a provision in the award agreement which provides that employees, including the named executive officers with at least ten years of service with the general partner, who leave the general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions of IRC Section 409(A).
With respect to Mr. Mason, in February 2016, the ETE Compensation Committee approved a one-time special incentive retention bonus in the amount of $6,300,000 (the “Special Bonus”).  The Special Bonus was approved by the ETE Compensation Committee based on a recommendation of ETE senior management in recognition of, among other things, (i) Mr. Mason’s appointment as the Executive Vice President and General Counsel of the General Partner; (ii) his 2015 calendar year performance; and (iii) his contributions to ETE and its family of partnerships on several key initiatives, including (a) the drop-down transactions by and between ETP and Sunoco LP, (b) the proposed merger transaction between the ETE and The Williams Companies, Inc., (c) the liquefied natural gas (LNG) export project of ETE, and (d) the simplification of the overall Energy Transfer family structure.  The approval of the Special Bonus by the ETE Compensation Committee was conditioned upon entry by Mr. Mason into a Retention Agreement provide thatwith ETE (the “Retention Agreement”) which provides (i) if, prior to the Class D units will convert in connection with any terminationthird (3rd) anniversary of the effective date of the Retention Agreement, Mr. Welch’s employment without “Cause” or his termination ofMason’s employment with Good Reason. All awards would convert in the eventETE or one of Mr. Welch’s terminationits affiliates terminates (other than as a result of (x) a termination without cause by ETE or by Mr. Mason for Good Reason; (y) his deathdeath; or disability.

135
Table(z) his permanent disability as determined by ETE), he will be obligated to remit and repay one-hundred percent (100%) of Contentsthe Special Bonus to ETE; (ii) if, after the third (3rd) anniversary but prior to the fourth (4th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment with ETE or one of its affiliates terminates (other than as a result of (x) a termination without cause by ETE or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability as determined by ETE), he will be obligated to remit and repay seventy-five percent (75%) of the Special Bonus to ETE; and (iii) if, after the fourth (4th) anniversary but prior to the fifth (5th) anniversary of the effective date of the Retention Agreement, Mr. Mason’s employment with ETE or one of its affiliates terminates (other than as a result of (x) a termination without cause by ETE or by Mr. Mason for Good Reason; (y) his death; or (z) his permanent disability as determined by ETE), he will be obligated to remit and repay fifty percent (50%) of the Special Bonus to ETE.  Mr. Mason and ETE entered into the Retention Agreement on February 24, 2016.

Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the DCETP NQDC Plan (other than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the DCETP NQDC Plan), distributions from the DC Planrespective plan would be made in accordance with the DC Plan’s normal distribution provisions.provisions of the respective plan. A change of control is generally defined in the DCETP NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).
CEO Pay Ratio
In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth below is information about the relationship of the annual total compensation of Mr. McReynolds, our President and the annual total compensation of our employees. We are using Mr. McReynolds for purposes of the CEO pay ratio as ETE does not have an elected Chief Executive Officer and Mr. McReynolds serves as ETE’s principal executive officer. Mr. Kelcy Warren serves as ETE’s Chairman and the Chairman and Chief Executive Officer of ETP. Additionally, for purposes of this disclosure we used the same data used for the ETP CEO pay ratio as the employee base supporting ETP is substantially the same employee base supporting ETE.
For the 2017 calendar year:
The annual total compensation of Mr. McReynolds, as reported in the Summary Compensation Tables of this Item 11was $1,367,413; and

The median total compensation of the employees supporting ETP (other than Mr. Warren) was $115,226.
Based on this information, for 2017 the ration of the annual total compensation of Mr. McReynolds to the median of the annual total compensation of the 8,494 employees supporting ETP, which is substantially the same employee base supporting ETE, as of December 31, 2017 was approximately 12 to 1.
To identify the median of the annual total compensation of the employees supporting ETE and ETP, the following steps were taken:
1.It was determined that, as of December 31, 2017, the applicable employee populations consisted of 8,494 with all of the identified individuals being employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent contractors in 2017 that are required to be included in our employee population for the CEO pay ratio evaluation.
2.To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records as reported on Form W-2 for 2017.
3.We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”
4.Once we identified our median employee, we combined all elements of the employee’s compensation for 2017 resulting in an annual compensation of $115,226. The difference between such employee’s total earnings and the employee’s total compensation represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $10,800) and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $5,846 per employee, includes $3,633 per employee on average matching contribution and $2,213 per employee on average profit sharing contribution (employees earning over $175,000 in base are ineligible for profit sharing)).
5.With respect to Mr. McReynolds, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table under this Item 11.
Director Compensation
Directors of LE GP, LLCour General Partner, who are employees of the LE GP, LLC, ETP GP or any of their subsidiaries, are not eligible for director compensation. In 2014,2017, the compensation arrangements for outside directors includeincluded a $50,000 annual retainer for services on the board andboard. If a director served on the ETE Audit Committee, such director would receive an annual retainer ($10,000 or $15,000 in the case of the chairman) and meeting attendance fees ($1,200) for services. If a director served on the Audit Committee. In 2014, membersETE Compensation Committee, such director would receive an annual cash retainer ($5,000 or $7,500 in the case of the Conflicts Committee received cash payments on a to-be-determined basis for each Conflicts Committee assignment. For their service on the Conflicts Committee during 2014, Messrs. Harkey, Ramseychairman) and Turner each received additional compensation of $15,000.meeting attendance fees ($1,200).
The outside directors of LE GP, LLCour General Partner are also entitled to an annual award under the Energy Transfer Equity, L.P. Long-Term IncentiveETE Plan equal to an aggregate of $100,000 divided by the closing price of ETE Common Unitscommon units on the date of grant. These ETE Common Unitscommon units will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the ETE Common Unitscommon units and is recognized over the vesting period. Distributions are paid during the vesting period.
The ETP Compensation Committee periodically reviews and makes recommendations regarding the compensation of the directors of ETP’s General Partner. In 2014, non-employee directors received an annual fee of $50,000 in cash. Additionally, the Chairman of ETP’s audit committee receives an annual fee of $15,000 and the members of ETP’s Audit Committee receive an annual fee of $10,000. The Chairman of the ETP Compensation Committee receives an annual fee of $7,500 and the members of the ETP Compensation Committee receive an annual fee of $5,000. For their service on the Conflicts Committee during 2014, Mr. Glaske received additional compensation of $10,000, Mr. Collins received additional compensation of $15,000 and Messrs. Grimm and Skidmore each received additional compensation of $25,000. ETP’s employee directors, including Messrs. Warren, McCrea and Welch, do not receive any fees for service as directors. In addition, the non-employee directors participate in ETP’s 2008 Incentive Plan. Each director of ETP’s General Partner who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary, who is elected or appointed to the board of ETP’s General Partner for the first time shall automatically receive, on the date of his or her election or appointment, an award of 2,500 unvested ETP common units. In 2014, non-employee ETP directors received annual grants of restricted ETP common units equal to an aggregate of $100,000 divided by the closing price of ETP’s common units on the date of grant. Beginning in 2013, the ETP common units granted to non-employee directors will vest 60% after the third year and the remaining 40% after the fifth year after the grant date. Previously, vesting was ratable over three years.
The compensation paid to the non-employee directors of our General Partner in 20142017 is reflected in the following table:
Name 
Fees Paid in Cash
($) (1)
 
Unit Awards
($) (2)
 
All Other Compensation
($)
 
Total
($)
 
Fees Paid in Cash(1)
($)
 
Unit Awards(2)
($)
 
All Other Compensation
($)
 
Total
($)
John D. Harkey, Jr. (3)
       
Richard D. Brannon        
As ETE director $49,644
 $100,028
 $—
 $149,672
 $83,965
 $99,991
 $—
 $183,956
As Regency director 19,325
 140,000
 —
 159,325
Matthew S. Ramsey (4)
 

     
As ETE director 103,317
 100,028
 —
 203,345
As Regency director 52,350
 72,950
 —
 125,300
As Sunoco LP director 35,733
 33,989
 —
 69,722
K. Rick Turner (5)
 

 

   
K. Rick Turner 

 

   
As ETE director 99,358
 100,028
 —
 199,386
 80,700
 99,991
 —
 180,691
As Sunoco LP Director 34,900
 33,989
 —
 68,889
 82,100
 100,008
 —
 182,108
William P. Williams (6)
 

     —
William P. Williams 

     
As ETE director 35,886
 —
 —
 35,886
 74,600
 99,991
 —
 174,591
As Sunoco LP Director 19,900
 33,989
 —
 53,889
     —
 —
(1) 
Fees paid in cash are based on amounts paid during the period.
(2) 
Unit award amounts reflect the aggregate grant date fair value of awards granted based on the market price of ETE Common Units, Regency Common Unitscommon units, ETP common units or Sunoco LP Common Units, accordingly, as of the grant date.

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(3)
Effective March 1, 2014, Mr. Harkey resigned from the Board of Directors of our General Partner and the Board of Directors of Regency GP LLC.
As of December 31, 2014,2017, Mr. Brannon had 7,716 unvested ETE restricted units outstanding, Mr. Turner had 5,29320,423 unvested ETE restricted units outstanding and Mr. RamseyWilliams had 5,047 unvested15,739 ETE restricted units outstanding. As
For 2018, the Board of December 31, 2014, Mr. Ramsey had 2,500 unvested Regency restricted units outstanding. Messrs. Ramsey, Turner and Williams are currentlyour General Partner has approved modifications to the compensation of non-employee directors of Sunoco LPour General Partner. The directors will receive an annual retainer fee of $100,000 in cash up from $50,000 in 2017. In addition, the Chairman of the Audit Committee will receive an annual fee of $25,000 up from $15,000 in 2017 and the members of the Audit Committee will receive an annual fee of $15,000 up from $10,000. The Chairman of our Compensation Committee will receive an annual fee of $15,000 up from 7,500 in 2017 and the members of our Compensation Committee will receive an annual fee of $7,500 up from $5,000 in 2017. The fees for membership on the Conflicts Committee will continue to be determined on a per instance basis for each had 747 unvested Sunoco LP restricted units outstanding asConflicts Committee assignment.
Additionally for 2018, the value of December 31, 2014.equity awards issued to the non-employee directors will remain equal to an aggregate of $100,000 to be divided by the closing price of our Common Units on the date of grant. Equity awards will also continue to vest 60% after the third year and the remaining 40% after the fifth year after the grant date.
The proposed compensation changes for the non-employee directors for 2018 were developed in consultation with Mr. Warren after considering the results of a review of directors’ compensation by Longnecker during 2017.
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
Equity Compensation Plan Information
At the time of our initial public offering, we adopted the Energy Transfer Equity, L.P. Long-Term Incentive Plan for the employees, directors and consultants of our General Partner and its affiliates who perform services for us. The long-term incentive plan provides for the following five types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The long-term incentive plan limits the number of units that may be delivered pursuant to awards to three million units. Units withheld to satisfy exercise prices or tax withholding obligations are available for delivery pursuant to other awards. The plan is administered by the compensation committee of the board of directors of our General Partner.

The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 2014:2017: 
Plan Category 
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)
 
Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)
 
Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
 
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)
 
Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)
 
Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
Equity compensation plans approved by security holders —
 $—
 —
 —
 $—
 —
Equity compensation plans not approved by security holders:            
Energy Transfer Equity, L.P. Long-Term Incentive Plan —
 —
 5,690,101
Class D Unit Agreement 1,540,000
 $—
 —
Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan 1,198,239
 —
 10,752,488
Total 1,540,000
 $—
 5,690,101
 1,198,239
 $—
 10,752,488

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Energy Transfer Equity, L.P. Units
The following table sets forth certain information as of February 18, 2015,16, 2018, regarding the beneficial ownership of our voting securities by (i) certain beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person not disclosed herein who beneficially owns more than 5% of our Common Units.
Title of Class 
Name and Address of
Beneficial Owner (1)
 
Beneficially
Owned (2)
 Percent of Class
Common Units 
Ray C. Davis (3)
 34,108,102
 6.3%
       
  
John W. McReynolds (4)
 12,499,944
 2.3%
  
Kelcy L. Warren (5)
 91,715,009
 17.0%
  
Jamie Welch (6)
 1,540,000
 *
  Marshall S. (Mackie) McCrea, III 1,416,100
 *
  Matthew S. Ramsey 26,159
 *
  K. Rick Turner 174,994
 *
  
William P. Williams (7)
 2,696,364
 *
  All Directors and Executive Officers as a group (7 persons) 110,068,570
 20.3%

Name and Address of
Beneficial Owner (1)
 
Beneficially
Owned (2)
 Percent of Class
Kelcy L. Warren (3)
 187,739,220
 17.4%
Ray C. Davis (4)
 70,058,606
 6.5%
John W. McReynolds (5)
 25,085,888
 2.3%
Thomas E. Long —
 *
Marshall S. (Mackie) McCrea, III 1,177,570
 *
Thomas P. Mason 583,000
 *
Brad Whitehurst (6)
 9,145
 *
Richard D. Brannon 38,400
 *
Matthew S. Ramsey 52,317
 *
K. Rick Turner (7)
 452,072
 *
William P. Williams (8)
 5,392,728
 *
All Directors and Executive Officers as a group (11 persons) 290,588,946
 26.9%
*Less than 1%

(1) 
The address for Mr. Davis is 5950 Sherry Lane, Dallas, Texas 75225. Messrs. McReynolds, Warren, Welch, McCrea, Ramsey, Turner and WilliamsThe address for all other listed beneficial owners is 3738 Oak Lawn Avenue,8111 Westchester Drive, Suite 600, Dallas, Texas 75219.75225.
(2) 
Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act.Act of 1934. Under that rule, a person is generally considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the disposition thereof or has the right to acquire either of those powers within sixty days. NatureThe nature of beneficial ownership for all listed persons is direct with sole investment and disposition power unless otherwise noted. The beneficial ownership of each listed person is based on 1,079,145,561 Common Units outstanding in the aggregate as of February 16, 2018. The number of Common Units shown does not include Common Units that may result from the conversion of ETE Series A Convertible Preferred Units, since such conversion is not expected to occur within sixty days of the date of this annual report.
(3) 
Includes 278,718 units79,102,200 Common Units held by Avatar BWKelcy Warren Partners, L.P. and 8,244,900 Common Units held by Kelcy Warren Partners II, L.P., the general partners of which are owned by Mr. Warren. Also includes 73,853,812 Common Units held by Seven Bridges Holdings, LLC, 20,846 unitsof which Mr. Warren is a member. Also includes 5,012 Common Units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and

dispositive power with Ray Davis. Also includes 601,076 Common Units held by LE GP, LLC. Mr. Warren may be deemed to own Common Units held by LE GP, LLC due to his ownership of 81.2% of its member interests. The voting and disposition of these Common Units is directly controlled by the board of directors of LE GP, LLC. Mr. Warren disclaims beneficial ownership of Common Units owned by LE GP, LLC other than to the extent of his interest in such entity. Also includes 84,000 Common Units held by Mr. Warren’s spouse.
(4)
Includes 41,692 Common Units held by Avatar Holdings LLC, 11,371,340 units1,092,436 Common Units held by Avatar BW, Ltd., 22,742,680 Common Units held by Avatar ETC Stock Holdings LLC, 1,434,474 units2,868,948 Common Units held by Avatar Investments LP, 48,834 units97,668 Common Units held by Avatar Stock Holdings, LLCLP and 390,984 units817,216 Common Units held by RCD Stock Holdings, LLC, all of which entities are owned or controlled by Mr. Davis. Also includes 9,520,182 units12,892,020 Common Units held by a remainder trust for Mr. Davis’ spouse and 4,351,688 units7,689,900 Common Units held by two trusts for the benefit of Mr. Davis’ grandchildren, for which Mr. Davis serves as trustee. Mr. Davis shares voting and dispositive power with his wife with respect to 9,538,266 unitsCommon Units held directly. Also includes 132,403 units264,806 Common Units attributable to the interest of Mr. Davis in ET Company Ltd and Three Dawaco, Inc., over which Mr. Davis exercises shared voting and dispositive power with Mr. Warren. Excludes Mr. Davis’ interest in 308,538 units held by LE GP, LLC. Mr. Davis may be deemed to own units held by LE GP, LLC due to his ownership of 18.8% of its member interests. The voting and disposition of these units is directly controlled by the board of directors of LE GP, LLC. Mr. Davis disclaims beneficial ownership of units owned by LE GP LLC other than to the extent of his interest in such entity.Ltd. Mr. Davis is a former executive officer of ETP and former director of our General Partner.
(4)(5) 
Includes 7,245,204 units14,490,408 Common Units held by McReynolds Energy Partners L.P. and 5,043,140 units10,086,280 Common Units held by McReynolds Equity Partners L.P., the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of unitsCommon Units owned by such limited partnerships other than to the extent of his interest in such entities.
(5)(6) 
Includes 39,551,100 units4,430 Common Units held by Kelcy Warren Partners, L.P. and 3,879,950 units held by Kelcy Warren Partners II, L.P., the general partners of which are owned byin a family trust. Mr. Warren. Also includes 35,926,908 units held by Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 132,403 units attributable to the interest of Mr. Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and dispositive power with Ray Davis. Also includes 300,538 units held by LE GP, LLC. Mr. Warren may be deemed to own units held by LE GP, LLC due to his ownership of 81.2% of its member interests. The voting and disposition of these units is directly controlled by the boardof directors of LE GP, LLC. Mr. WarrenWhitehurst disclaims beneficial ownership of units ownedthe Common Units held by LE GP, LLC other thansuch trust, except to the extent of his interest in such entity. Also includes 42,000 units held by Mr. Warren’s spouse.
trust.
(6)
Represents Class D Units convertible into 1,540,000 Common Units. The Class D Units have voting and distribution rights equal to Common Units and are therefore included in this table.

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(7) 
Includes 1,669,342 units(i) 89,084 Common Units held in a partnership controlled by the Stephens Group, Mr. Turner’s former employer; (ii) 8,000 Common Units held by the WilliamsTurner Family Partnership; and (iii) 157,790 Common Units held by the Turner Liquidating Trust. The voting and disposition of the Common Units held by the Stephens Group partnership is controlled by the board of directors of the Stephens Group. With respect to the Common Units held by the Turner Family Partnership, LtdMr. Turner exercises voting and 1,516,014 unitsdispositive power as the general partner of the partnership; however, he disclaims beneficial ownership of these Common Units, except to the extent of his interest in the partnership. With respect to the Common Units held by the Turner Liquidating Trust, Mr. Turner exercises one-third of the shared voting and dispositive power with the administrator of the liquidating trust and Mr. Turner’s ex-wife, who beneficially owns an additional 157,790 Common Units. Mr. Turner disclaims beneficial ownership of the Common Units owned by his ex-wife.
(8)
Includes 2,338,484 Common Units held by the William P and Jane C Family Partnership Ltd. and 3,032,028 Common Units held by the Bar W Barking Cat Ltd.LTD Partnership. Mr. Williams disclaims beneficial ownership of unitsCommon Units owned by such entities, except to the extent of his interest in such entities.
In connection with the Parent Company Credit Agreement, ETE and certain of its subsidiaries entered into a Pledge and Security Agreement (the “Security Agreement”) with Credit Suisse AG, Cayman Islands Branch, as collateral agent (the “Collateral Agent”). The Security Agreement secures all of ETE’s obligations under the Parent Company Credit Agreement and grants to the Collateral Agent a continuing first priority lien on, and security interest in, all of ETE’s and the other grantors’ tangible and intangible assets.
ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
At December 31, 2014,2017, our equity interests in ETP and RegencySunoco LP consisted of 100% of the respective general partner interestinterests and IDRs, as well as the following:
 ETP Regency
Units held by wholly-owned subsidiaries:   
Common units30,841,069
 57,157,356
ETP Class H units50,160,000
 —
Units held by less than wholly-owned subsidiaries:   
Common units—
 31,372,419
Regency Class F units—
 6,274,483
approximately 27.5 million ETP common units, approximately 2.3 million Sunoco LP common units and 12 million Sunoco LP Series A Preferred Units held by us or our wholly-owned subsidiaries. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency,Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and cash flows from the operations of Lake Charles LNG.
ETP and RegencySunoco LP are required by their respective partnership agreements to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of their respective general partners.
Immediately following the closing of ETP’s acquisition of Sunoco, Inc., ETE contributed its interest in Southern Union into ETP Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in ETP Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco, Inc. to ETP Holdco and retained a 40% equity interest in ETP Holdco. Prior to the contribution of Sunoco, Inc. to ETP Holdco, Sunoco, Inc. contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90.7 million ETP Class F Units representing limited partner interests in ETP. The ETP Class F Units were entitled to 35% of the quarterly cash distribution generated by ETP and its subsidiaries other than ETP Holdco, subject to a maximum cash distribution of $3.75 per ETP Class F Unit per year, which is the current level. In April 2013, all of the outstanding ETP Class F Units were exchanged for ETP Class G Units on a one-for-one basis. The ETP Class G Units have terms that are substantially the same as the ETP Class F Units, with the principal difference between the ETP Class G Units and the ETP Class F Units being that allocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss.
On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.
On April 30, 2013, ETP acquired ETE’s 60% interest in ETP Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “ETP Holdco Acquisition”). As a result, ETP now owns 100% of ETP Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled ETP Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.

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Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its ETP Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “ETP Class H Units”), which are generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners, (ii) distributions from available cash at ETP for each quarter equal to 50.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the ETP Class H Units, for any previous quarters.
In December 2014, ETP and ETE announced the final terms of a transaction, whereby ETE will transfer 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transactions”). In connection with this transaction, ETP will also issue 100 ETP Class I Units. In addition, ETE and ETP agreed to reduce the IDR subsidies that ETE previously agreed to provide to ETP, with such reductions occurring in 2015 and 2016. This transaction is expected to close in March 2015.
On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, from ETP in exchange for the redemption by ETP of 18.7 million. The transaction was effective as of January 1, 2014.
In connection with ETE’s 2014 acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 98 to our consolidated financial statements.

Mr. McCrea, a current director of LE GP, LLC, our General Partner, is also a director and executive officer of ETP GP. In addition, Mr. Warren, the Chairman of our Board of Directors, is also a director and executive officer of ETP GP.
For a discussion of director independence, see Item 10. “Directors, Executive Officers and Corporate Governance.”
As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a related party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those determinations in light of its contractually-limited fiduciary duties to the Unitholders. The partnership agreement of ETE provides that any matter approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to ETE, approved by all the partners of ETE and not a breach by the General Partner or its Board of Directors of any duties they may owe ETE or the Unitholders (see “Risks Related to Conflicts of Interest” in Item“Item 1A. Risk Factors” in this annual report).
The Parent Company has agreements with subsidiaries to provide or receive various general and administrative services. The Parent Company pays ETP to provide services on its behalf and the behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries, which include the reimbursement of various general and administrative services for expenses incurred by ETP on behalf of those subsidiaries. All such amounts have been eliminated in our consolidated financial statements.
ETP haspreviously had an operating lease agreement with the former owners of ETG, which ETP acquired in 2009. These former owners includeincluding Mr. Warren and Mr. Ray C. Davis, a formerDavis. ETP board member. ETP payspaid these former owners $5$5 million in annual operating lease payments per year through during the term of the lease and made a one-time payment of $8.8 million in August 2017. and we retained the equipment when the lease expired at that time. With respect to the related party transaction with ETG, the Conflicts Committee of ETP met numerous times prior to the consummation of the transaction to discuss the terms of the transaction. The committee made the determination that the sale of ETG to ETP was fair and reasonable to ETP and that the terms of the operating lease between ETP and the former owners of ETG are fair and reasonable to ETP.

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ITEM 14.  PRINCIPAL ACCOUNTING FEES AND SERVICES
The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered:rendered (dollars in millions):
 
Years Ended December 31,Years Ended December 31,
2014 20132017 2016
Audit fees (1)
$8,484,000
 $8,274,000
$11.5
 $9.9
Audit-related fees (2)
895,893
 682,300
—
 0.6
Tax fees (3)
79,000
 —
—
 0.1
Total$9,458,893
 $8,956,300
$11.5
 $10.6
 
(1) 
Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and services related to the audit of our internal controls over financial reporting.
(2) 
Includes fees in 2014 and 20132016 for financial statement audits and interim reviews of subsidiary entities in connection with contribution and sale transactions. Includes fees in 2013 for audits of Sunoco, Inc.’s benefit plans. Includes fees in 2014 and 20132016 in connection with the service organization control report on Panhandle’s centralized data center.
(3) 
Includes fees related to state and local tax consultation.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices. The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2017 and 2016 were pre-approved by the Audit Committee in accordance with this policy.

The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting, regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually, uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
the auditors’ internal quality-control procedures;
any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
the independence of the external auditors;
the aggregate fees billed by our external auditors for each of the previous two years; and
the rotation of the lead partner.

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PART IV
ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this Report:
Page
(1)
(1) Financial Statements -– see Index to Financial Statements appearing on page F-1.
F - 1
(2)
(2) Financial Statement Schedules - None.
– None
(3) Exhibits – see Index to Exhibits
149
(b) Exhibits - see Index to Exhibits
149 set forth
(c) Financial statements of affiliates whose securities are pledged as collateral - See Index to Financial Statements on page S-1.
E-1S - 1.
(b) Exhibits - see Index to Exhibits set forth on page E-1.
(c) Financial statements of affiliates whose securities are pledged as collateral - See Index to Financial Statements on page S-1.

The Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP and Regency constituteconstitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP and Regency are required under Rule 3-16 to be included in this Annual Report on Form 10-K and have been included herein.
The Parent Company’s interestsinterest in ETP GP ETE Common Holdings, LLC, ETE GP Acquirer LLC, and Regency GP LP (collectively, the “Non-Reporting Entities”) also constituteconstitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of the Non-Reporting EntitiesETP GP would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. None of the Non-Reporting Entities hasETP GP does not have substantive operations of its own; rather, each ofETP GP only owns the Non-Reporting Entities holds only direct or indirect interestsgeneral partner interest in ETP, Regency and/or the consolidated subsidiaries of ETP and Regency.ETP.
As further discussed in Note 6 to the consolidated financial statements, as referenced in (a) above, the financial statements of the Non-Reporting EntitiesETP GP would substantially duplicate information that is available in the financial statements of ETP and Regency.ETP. Therefore, the financial statements of the Non-Reporting EntitiesETP GP have been excluded from this Annual Report on Form 10-K.

ITEM 16. FORM 10-K SUMMARY
None.


INDEX TO EXHIBITS
The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.
142
Exhibit
Number
Description
2.1
Redemption and Transfer Agreement, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. dated November 19, 2013 (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-32740, filed November 21, 2013)
2.2
Exchange and Repurchase Agreement, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated December 23, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed December 23, 2014)
2.3
Agreement and Plan of Merger, dated as of September 28, 2015, among Energy Transfer Corp LP, ETE Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC, ETE GP, LLC and The Williams Companies, Inc. (incorporated by reference to Exhibit 2.1 of Form 8-K/A, File No. 1-32740, filed October 2, 2015)
2.4
Agreement and Plan of Merger, dated as of January 25, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners, GP, L.P., Regency Energy Partners LP, Regency GP LP and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-11727, filed January 26, 2015)
2.5
Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Rendezvous I LLC, Rendezvous II LLC, Regency Energy Partners LP, Regency GP LP, ETE GP Acquirer LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K, File No. 1-11727, filed February 19, 2015)
2.6
Agreement and Plan of Merger, dated as of November 20, 2016, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Sunoco Logistics Partners L.P., Sunoco Partners LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporate by reference to Exhibit 2.1 of Form 8-K File No. 1-11727, filed November 21, 2016
2.7
Amendment No. 1 to Agreement and Plan of Merger, dated as of December 16, 2016, by and among Sunoco Logistics Partners L.P., Sunoco Partners LLC, SXL Acquisition Sub LLC, SXL Acquisition Sub LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETP Acquisition Sub, LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K File No. 1-11727, filed December 21, 2016
2.8
Contribution Agreement, dated as of January 15, 2018, by and among USA Compression Partners, LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETC Compression, LLC and, solely for certain purposes therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed January 16, 2018).
2.9
Purchase Agreement, dated as of January 15, 2018, by and among USA Compression Holdings, LLC, Energy Transfer Equity, L.P., Energy Transfer Partners, L.L.C. and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.2 to the Registrant’s Form 8-K filed January 16, 2018).
3.1
Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1, File No. 333-128097, filed September 2, 2005)
3.2
Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed February 14, 2006)
3.3
Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 of Form 10-K, File No. 1-32740, filed November 29, 2006)
3.4
Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 of Form 8-K, File No. 1-32740, filed November 13, 2007)
3.5
Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed June 2, 2010)
3.6
Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed December 27, 2013)
3.7
Amendment No. 5 to the Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated as of March 8, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed March 9, 2016)

Table of Contents
Exhibit
Number
Description
4.1
Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-32740, filed September 20, 2010)
4.2
First Supplemental Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.15 of Form 8-K, File No. 1-32740, filed September 20, 2010)
4.3
Second Supplemental Indenture, dated December 20, 2011 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form S-3, File No. 1-32740, filed November 14, 2013)
4.4
Second Supplemental Indenture, dated February 16, 2012 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-32740, filed February 17, 2012)
4.5
Fourth Supplemental Indenture, dated December 2, 2013 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed December 2, 2013)
4.6
Fifth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed May 28, 2014)
4.7
Sixth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-32740, filed May 28, 2014)
4.8
Seventh Supplemental Indenture, dated May 22, 2015 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed May 22, 2015)
4.9
Eighth Supplemental Indenture dated October 18, 2017 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed October 18th, 2017)
10.1+
Energy Transfer Equity, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.25 of Form S-1, File No. 333-128097, filed December 20, 2005)
10.2+
Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.26 of Form S-1, File No. 333-128097, filed December 20, 2005)
10.3
Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P. and Energy Transfer Investments, L.P. (incorporated by reference to Exhibit 10.38 of Form 10-K, File No. 1-32740, filed November 29, 2006)
10.4
Registration Rights Agreement, dated November 27, 2006, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed November 30, 2006)
10.5+
LE GP, LLC Outside Director Compensation Policy (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed December 26, 2006)
10.6
Registration Rights Agreement, dated March 2, 2007, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed March 5, 2007)
10.7
Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural Gas Partners VI, L.P. and Enterprise GP Holdings, L.P. (incorporated by reference to Exhibit 10.45 of Form 8-K, File No. 1-32740, filed May 7, 2007)
10.8
Letter Agreement, dated as of April 29, 2012, by and among Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed May 1, 2012)
10.9
Shared Services Agreement dated as of August 26, 2005, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.30 of Form S-1/A (333-128097) filed December 20, 2005).

10.10
Second Amendment, dated April 30, 2013, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.(incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-32740, filed May 1, 2013)
10.11
Third Amendment, dated February 19, 2014, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010 and April 30, 2013 by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 19, 2014)
10.12
Exchange and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated August 7, 2013 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed August 8, 2013)

Exhibit
Number
Description
10.13
Credit Agreement, dated as of March 24, 2017 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed March 30, 2017)
10.14
Second Amended and Restated Pledge and Security Agreement, dated December 2, 2013 among Energy Transfer Equity, L.P., the other grantors named therein and U.S. Bank National Association, as collateral agent (incorporated by reference to Exhibit 10.3 of Form 8-K, File No. 1-32740, filed December 2, 2013)
10.15+
Retention Agreement, by and among Energy Transfer Equity, L.P. and Thomas P. Mason, dated February 24, 2016.
10.16
Senior Secured Term Loan Agreement, dated February 2, 2017 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 3, 2017.)
10.1*+
Amended and Restated Energy Transfer Equity, L.P. Long-Term Incentive Plan
12.1*
Computation of Ratio of Earnings to Fixed Charges
18.1*
Preferability Letter from Grant Thornton LLP
21.1*
List of Subsidiaries
23.1*
Consent of Grant Thornton LLP related to Energy Transfer Equity, L.P.
23.2*
Consent of Grant Thornton LLP related to Energy Transfer Partners, L.P.
31.1*
Certification of President (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**
Certification of President (Principal Executive Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**
Certification Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1
Statement of Policies Relating to Potential Conflicts among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and Regency Energy Partners LP dated as of April 26, 2011 (incorporated by reference to Exhibit 99.1 of Form 10-Q, file No. 1-32740, filed August 8, 2011)
101*Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016; (ii) our Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015; (iii) our Consolidated Statements of Comprehensive Income for years ended December 31, 2017, 2016 and 2013; (iv) our Consolidated Statement of Equity for the years ended December 31, 2017, 2016 and 2015; and (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015
*Filed herewith.
**Furnished herewith.
+Denotes a management contract or compensatory plan or arrangement.


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
  ENERGY TRANSFER EQUITY, L.P.
    
  By: LE GP, LLC,
    its general partner
    
Date:March 2, 2015February 23, 2018By: /s/    Jamie WelchThomas E. Long
    Jamie WelchThomas E. Long
    
Group Chief Financial Officer (duly
authorized to sign on behalf of the registrant)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated:
 
Signature Title Date
     
/s/    John W. McReynolds Director and President March 2, 2015February 23, 2018
John W. McReynolds (Principal Executive Officer)  
     
/s/    Jamie WelchThomas E. Long Director and Group Chief Financial Officer and Head of Business Development (Principal Financial and Accounting Officer) March 2, 2015February 23, 2018
Jamie WelchThomas E. Long   
     
/s/    Kelcy L. Warren Director and Chairman of the Board March 2, 2015February 23, 2018
Kelcy L. Warren
/s/    Richard D. BrannonDirectorFebruary 23, 2018
Richard D. Brannon    
     
/s/    Marshall S. McCrea, III Director March 2, 2015February 23, 2018
Marshall S. McCrea, III    
     
/s/    Matthew S. Ramsey Director March 2, 2015February 23, 2018
Matthew S. Ramsey    
     
/s/    K. Rick Turner Director March 2, 2015February 23, 2018
K. Rick Turner    
     
/s/    William P. Williams Director March 2, 2015February 23, 2018
William P. Williams
    




143

INDEX TO EXHIBITS
The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.
Exhibit
Number
2.1General Partner Purchase Agreement, dated May 10, 2010, by and among Regency GP Acquirer, L.P., Energy Transfer Equity, L.P. and ETE GP Acquirer LLC (incorporated by reference to Exhibit 2.1 of Form 8-K/A, file No. 1-32740, filed May 13, 2010)
2.2Contribution Agreement, dated May 10, 2010, by and among Energy Transfer Equity, L.P., Regency Energy Partners LP and Regency Midcontinent Express LLC (incorporated by reference to Exhibit 2.3 of Form 8-K/A, file No. 1-32740, filed May 13, 2010)
2.3Agreement and Plan of Merger by and among Energy Transfer Equity, L.P., Sigma Acquisition Corporation and Southern Union Company, dated as of June 15, 2011, as Amended and Restated as of July 4, 2011 and July 19, 2011 (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed July 5, 2011)
2.3.1Amendment No. 1, dated as of September 14, 2011, to Second Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, by and among Energy Transfer Equity, L.P., Sigma Acquisition Corporation and Southern Union Company (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed September 15, 2011)
2.4Support Agreement dated June 15, 2011 by and among Energy Transfer Equity, L.P., Sigma Acquisition Corporation, and certain stockholders of Southern Union Company (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed July 5, 2011)
2.5Amended and Restated Agreement and Plan of Merger by and among Energy Transfer Partners, L.P., Citrus ETP Acquisition, L.L.C., Energy Transfer Equity, L.P., Southern Union Company, and CrossCountry Energy, LLC, dated as of July 19, 2011 (incorporated by reference to Exhibit 2.2 of Form 8-K, file No. 1-32740, filed July 20, 2011)
2.5.1Amendment No. 1, dated as of September 14, 2011, to Amended and Restated Agreement and Plan of Merger, dated as of July 19, 2011, by and between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K, file No. 1-32740, filed September 15, 2011)
2.5.2Amendment No. 2, dated as of March 23, 2012, to Amended and Restated Agreement and Plan of Merger by and among Energy Transfer Equity, L.P., Energy Transfer Partners, L.P., Citrus ETP Acquisition, L.L.C, Southern Union Company, and CrossCountry Energy, LLC, dated as of July 19, 2011 (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed March 28, 2012)
2.6Agreement and Plan of Merger, dated as of April 29, 2012 by and among Energy Transfer Partners, L.P., Sam Acquisition Corporation, Energy Transfer Partners GP, L.P., Sunoco, Inc. and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed May 1, 2012)
2.6.1Amendment No. 1, dated as of June 15, 2012, to the Agreement and Plan of Merger, dated as of April 29, 2012, by and among Energy Transfer Partners, L.P., Sam Acquisition Corporation, Energy Transfer Partners GP, L.P., Sunoco, Inc., and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K, file No. 1-32740, filed June 20, 2012)
2.7Transaction Agreement, dated as of June 15, 2012, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Heritage Holdings, Inc., Energy Transfer Equity, L.P., ETE Sigma Holdco, LLC and ETE Holdco Corporation (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed June 20, 2012)
2.8Redemption and Transfer Agreement by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. dated November 19, 2013 (incorporated by reference to Exhibit 2.1 of Form 8-K, file No. 1-32740, filed November 21, 2013)
3.1Certificate of Conversion of Energy Transfer Company, L.P. (incorporated by reference to Exhibit 3.1 of Form S-1, file No. 333-128097, filed September 2, 2005)
3.2Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1, file No. 333-128097, filed September 2, 2005)
3.3Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed February 14, 2006)
3.3.1Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.3.1 of Form 10-K, file No. 1-32740, filed November 29, 2006)
3.3.2Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.3.2 of Form 8-K, file No. 1-32740, filed November 13, 2007)
3.3.3Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed June 2, 2010)


E- 1

Exhibit
Number
3.4Certificate of Conversion of LE GP, LLC (incorporated by reference to Exhibit 3.4 of Form S-1, file No. 333-128097, filed September 2, 2005)
3.5Certificate of Formation of LE GP, LLC (incorporated by reference to Exhibit 3.5 of Form S-1, file No. 333-128097, filed September 2, 2005)
3.6Amended and Restated Limited Liability Company Agreement of LE GP, LLC (incorporated by reference to Exhibit 3.6.1 of Form 8-K, file No. 1-32740, filed May 8, 2007)
3.6.1Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of LE GP, LLC (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed December 23, 2009)
3.7Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.) (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-11727, filed July 28, 2009)
3.8Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 3.3 of Form 10-Q, file No. 1-11727, filed April 14, 2004)
3.9Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.5 of Form 10-Q, file No. 1-11727, filed July 10, 2007)
3.10Fourth Amended and Restated Limited Liability Company Agreement of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.6 of Form 8-K, file No. 1-11727, filed August 10, 2010)
3.11Certificate of Formation of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13 of Form S-1/A, file No. 333-128097, filed December 20, 2005)
3.11.1Certificate of Amendment of Energy Transfer Partners, L.L.C. (incorporated by reference to Exhibit 3.13.1 of Form S-1/A, file No. 333-128097, filed December 20, 2005)
3.12Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P. (incorporated by reference to Exhibit 3.14 of Form S-1/A, file No. 333-128097, filed December 20, 2005)
3.13Second Amendment to Amended and Restated Limited Liability Company Agreement of Regency GP, L.L.C. (incorporated by reference to Exhibit 3.2 of Form 8-K, file No. 1-32740, filed August 10, 2010)
3.7.1Amendment No. 1, dated March 26, 2012, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated July 28, 2009 (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed March 28, 2012)
3.9.1Amendment No. 2, dated March 26, 2012, to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P., dated April 17, 2007 (incorporated by reference to Exhibit 3.2 of Form 8-K, file No. 1-32740, filed March 28, 2012)
3.10.1Amendment No. 1, dated March 26, 2012, to the Fourth Amended and Restated Agreement of Limited Liability Company Agreement of Energy Transfer Partners, L.L.C., dated August 10, 2010 (incorporated by reference to Exhibit 3.3 of Form 8-K, file No. 1-32740, filed March 28, 2012)
3.7.2Amendment No. 4, dated April 30, 2013, to the Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., as amended (incorporated by reference to Exhibit 3.1 of Form 8-K, file No. 1-32740, filed May 1, 2013)
4.1Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, file No. 1-11727, filed January 19, 2005)
4.2First Supplemental Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, file No. 1-11727, filed January 19, 2005)
4.3Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005 (incorporated by reference to Exhibit 10.45 of Form 10-Q, file No. 1-11727, filed April 11, 2005)
4.4Notation of Guarantee (incorporated by reference to Exhibit 10.46 of Form 10-Q, file No. 1-11727, filed April 11, 2005)
4.5Registration Rights Agreement dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and the initial purchasers party thereto (incorporated by reference to Exhibit 4.3 of Form 8-K, file No. 1-11727, filed January 19, 2005)
4.6Joinder to Registration Rights Agreement dated February 24, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 10.39.1 of Form 10-Q, file No. 1-11727, filed April 11, 2005)
4.7Third Supplemental Indenture dated July 29, 2005, to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein, and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, file No. 1-11727, filed August 2, 2005)

E- 2


Exhibit
Number
4.8Registration Rights Agreement dated July 29, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein, and the initial purchasers party thereto (incorporated by reference to Exhibit 4.2 of Form 8-K, file No. 1-11727, filed August 2, 2005)
4.9Form of Senior Indenture of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 4.9 of Form S-3, file No. 333-136429, filed August 9, 2006)
4.10Form of Subordinated Indenture of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 4.10 of Form S-3, file No. 333-136429, filed August 9, 2006)
4.11Fourth Supplemental Indenture dated as of June 29, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.13 of Form 10-K, file No. 1-11727, filed November 13, 2006)
4.12Fifth Supplemental Indenture dated as of October 23, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, file No. 1-11727, filed October 25, 2006)
4.13Sixth Supplemental Indenture dated March 28, 2008, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, file No. 1-11727, filed March 28, 2008)
4.14Seventh Supplemental Indenture dated December 23, 2008, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, file No. 1-11727, filed December 23, 2008)
4.15Eighth Supplemental Indenture dated April 7, 2009, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, file No. 1-11727, filed April 7, 2009)
4.16Energy Transfer Partners, L.P. 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit A of Form DEF 14A, file No. 1-11727, filed November 21, 2008)
4.17Registration Rights Agreement by and among Energy Transfer Equity, L.P. and Regency GP Acquirer, L.P., dated as of May 26, 2010 (incorporated by reference to Exhibit 4.14 of Form 8-K, file No. 1-32740, filed June 2, 2010)
4.18Indenture dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.14 of Form 8-K, file No. 1-32740, filed September 20, 2010)
4.19First Supplemental Indenture dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.15 of Form 8-K, file No. 1-32740, filed September 20, 2010)
4.20Second Supplemental Indenture dated as of February 16, 2012, between Energy Transfer Equity, L.P., and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 of Form 8-K, file No. 1-32740, filed February 17, 2012)
4.21Third Supplemental Indenture dated April 24, 2012 to Indenture dated September 20, 2010 between Energy Transfer Equity, L.P. and US Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 10-Q, file No. 1-32740, filed August 8, 2012)
4.22Registration Rights Agreement, dated April 30, 2013, by and between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 4.1 of Form 8-K, file No. 1-32740, filed May 1, 2013)
4.23Fourth Supplemental Indenture dated December 2, 2013 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 of Form 8-K, file No. 1-32740, filed December 2, 2013)
4.24Fifth Supplemental Indenture dated May 28, 2014 (incorporated by reference to Exhibit 4.2 of Form 8-K, file No. 1-32470, filed May 28, 2014)
4.25Sixth Supplemental Indenture dated May 28, 2014 (incorporated by reference to Exhibit 4.3 of Form 8-K, file No. 1-32470, filed May 28, 2014)
10.1Purchase and Sale Agreement dated January 26, 2005, among HPL Storage, LP and AEP Energy Services Gas Holding Company II, L.L.C., as Sellers, and LaGrange Acquisition, L.P., as Buyer (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-11727, filed February 1, 2005)
10.2Cushion Gas Litigation Agreement dated January 26, 2005, among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and LaGrange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-11727, filed February 1, 2005)


E- 3

Exhibit
Number
10.3.1+Energy Transfer Partners, L.P. Amended and Restated 2004 Unit Plan (incorporated by reference to Exhibit 10.6.6 of Form 10-Q, file No. 1-11727, filed August 11, 2008)
10.3.2+Energy Transfer Partners, L.P. Second Amended and Restated 2008 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 of Form 10-K, file No. 1-11727, filed February 26, 2015)
10.3.3+Energy Transfer Partners Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-11727, filed March 31, 2010)
10.3.4+Form of Grant Agreement under the Energy Transfer Partners, L.P. Amended and Restated 2004 Unit Plan and the Energy Transfer Partners, L.P. 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-11727, filed November 1, 2004)
10.3.5+Energy Transfer Partners, L.P. Annual Bonus Plan (incorporated by reference to Exhibit 10.2 of Form 10-Q, file No. 1-11727, filed August 7, 2014)
10.4Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P. (incorporated by reference to Exhibit 4.1 of Form 8-K, file No. 1-11727, filed February 13, 2002)
10.5Unitholder Rights Agreement dated January 20, 2004, among Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP LP and LaGrange Energy, L.P. (incorporated by reference to Exhibit 4.2 of Form 10-Q, file No. 1-11727, filed April 14, 2004)
10.6Registration Rights Agreement for Limited Partnership Units of LaGrange Energy, L.P. (incorporated by reference to Exhibit 10.47 of Form S-1, file No. 333-128097, filed October 13, 2005)
10.7+Energy Transfer Equity, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.25 of Form S-1, file No. 333-128097, filed December 20, 2005)
10.8+Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.26 of Form S-1, file No. 333-128097, filed December 20, 2005)
10.9Second Amended and Restated Credit Agreement, dated October 27, 2011, among Energy Transfer Partners, L.P., the borrower, and Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A., as syndication agent, BNP Paribas, JPMorgan Chase Bank, N.A. and the Royal Bank of Scotland PLC, as co-documentation agents, and Citibank, N.A., Credit Suisse, Cayman Islands Branch, Deutsche Bank Securities, Inc., Morgan Stanley Bank, Suntrust Bank and UBS Securities, LLC, as senior managing agents, and other lenders party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-11727, filed November 2, 2011)
10.10Contribution and Conveyance Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P., and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.35 of Form 10-K, file No. 1-32740, filed November 29, 2006)
10.11Contribution, Assumption and Conveyance Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P., and Energy Transfer Investments, L.P. (incorporated by reference to Exhibit 10.36 of Form 10-K, file No. 1-32740, filed November 29, 2006)
10.12Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.1.10 of Form 8-K, file No. 1-11727, filed November 3, 2006)
10.13Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P. and Energy Transfer Investments, L.P. (incorporated by reference to Exhibit 10.38 of Form 10-K, file No. 1-32740, filed November 29, 2006)
10.14Purchase and Sale Agreement, dated as of September 14, 2006, among Energy Transfer Partners, L.P. and EFS-PA, LLC (a/k/a GE Energy Financial Services), CDPQ Investments (U.S.) Inc., Lake Bluff, Inc., Merrill Lynch Ventures, L.P. and Kings Road Holding I LLC (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-11727, filed September 18, 2006)
10.15Redemption Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and CCE Holdings, LLC (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-11727, filed September 18, 2006)
10.16Letter Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and Southern Union Company (incorporated by reference to Exhibit 10.3 of Form 8-K, file No. 1-11727, filed September 18, 2006)
10.17Registration Rights Agreement, dated November 27, 2006, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, file No. 1-32740, filed November 30, 2006)
10.18+LE GP, LLC Outside Director Compensation Policy (incorporated by reference to Exhibit 99.1 of Form 8-K, file No. 1-32740, filed December 26, 2006)
10.19Registration Rights Agreement, dated March 2, 2007, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, file No. 1-32740, filed March 5, 2007)

E- 4

Exhibit
Number
10.20Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural Gas Partners VI, L.P. and Enterprise GP Holdings, L.P. (incorporated by reference to Exhibit 10.45 of Form 8-K, file No. 1-32740, filed May 7, 2007)
10.21Note Purchase Agreement, dated as of November 17, 2004, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.55 of Form 10-Q, file No. 1-11727, filed July 10, 2007)
10.21.1Amendment No. 1 to the Note Purchase Agreement, dated as of April 18, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.55.1 of Form 10-Q, file No. 1-11727, filed July 10, 2007)
10.22Note Purchase Agreement, dated as of May 24, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.56 of Form 10-Q, file No. 1-11727, filed July 10, 2007)
10.23Second Amended and Restated Support Agreement, dated as of July 19, 2011, by and among, Energy Transfer Equity, L.P., Sigma Acquisition Corporation and certain stockholders of Southern Union Company (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed July 20, 2011)
10.24Guarantee of Collection, made as of March 26, 2012, by Citrus ETP Finance LLC, to Energy Transfer Partners, L.P. under the Indenture dated as of January 18, 2005, as supplemented by the Tenth Supplemental Indenture dated as of January 17, 2012 (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed March 28, 2012)
10.25Support Agreement, dated March 26, 2012, by and among PEPL Holdings, LLC, Energy Transfer Partners, L.P. and Citrus ETP Finance LLC (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-32740, filed March 28, 2012)
10.26Letter Agreement, dated as of April 29, 2012, by and among Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed May 1, 2012)
10.27Purchase and Sale Agreement dated as of December 14, 2012 among Southern Union Company, Plaza Missouri Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc. (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed December 17, 2012)
10.28Purchase and Sale Agreement dated as of December 14, 2012 among Southern Union Company, Plaza Massachusetts Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc. (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-32740, filed December 17, 2012)
10.29First Amendment, dated April 30, 2013, to the Services Agreement, effective as of May 26, 2010, by and among Energy Transfer Equity, L.P., ETE Services Company LLC and Regency Energy Partners LP (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed May 1, 2013)
10.30Second Amendment, dated April 30, 2013, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.(incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-32740, filed May 1, 2013)
10.31Exchange and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC dated August 7, 2013 (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed August 8, 2013)
10.32Credit Agreement dated as of December 2, 2013 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed December 2, 2013)
10.33Senior Secured Term Loan Agreement dated as of December 2, 2013 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-32740, filed December 2, 2013)
10.34Second Amended and Restated Pledge and Security Agreement dated December 2, 2013 among Energy Transfer Equity, L.P., the other grantors named therein and U.S. Bank National Association, as collateral agent (incorporated by reference to Exhibit 10.3 of Form 8-K, file No. 1-32740, filed December 2, 2013)
10.35Class D Unit Agreement (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed December 27, 2013)
10.36Third Amendment, dated February 19, 2014, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010 and April 30, 2013 by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed February 19, 2014)
10.37Common Unit Purchase Agreement, dated June 4, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed June 5, 2014)
10.38Registration Rights Agreement, dated June 4, 2014 (incorporated by reference to Exhibit 10.2 of Form 8-K, file No. 1-32740, filed June 5, 2014)

E- 5

Exhibit
Number
10.39+Energy Transfer Partners, L.L.C. Annual Bonus Plan effective January 1, 2014 (incorporated by reference to Exhibit 10.2 of Form 10-Q, file No. 1-11727, filed August 7, 2014)
10.40Energy Transfer Equity, L.P. Incremental Loan Agreement No. 1, dated April 16, 2014 (incorporated by reference to Exhibit 10.5 of Form 10-Q, file No. 1-32470, filed August 7, 2014)
10.41Energy Transfer Equity, L.P. Amendment and Incremental Commitment Agreement No. 2, dated May 6, 2014 (incorporated by reference to Exhibit 10.6 of Form 10-Q, file No. 1-32470, filed August 7, 2014)
10.42Exchange and Repurchase Agreement, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated December 23, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32470, filed December 29, 2014)
10.43Amendment and Incremental Commitment Agreement No. 3 dated as of February 10, 2015 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, file No. 1-32740, filed February 17, 2015)
12.1*Computation of Ratio of Earnings to Fixed Charges.
21.1*List of Subsidiaries.
23.1*Consent of Grant Thornton LLP related to Energy Transfer Equity, L.P.
23.2*Consent to Grant Thornton LLP related to Energy Transfer Partners, L.P.
23.3*Consent of Grant Thornton LLP related to Regency Energy Partners LP.
23.4*Consent of Grant Thornton LLP related to RIGS Haynesville Partnership Co.
23.5*Consent of Ernst & Young LLP related to Sunoco Logistics Partners L.P.
23.6*Consent of Ernst & Young LLP related to Susser Holdings Corporation.
23.7*Consent of Ernst & Young LLP related to Sunoco LP.
23.8*Consent of PricewaterhouseCoopers LLP related to Midcontinent Express Pipeline LLC.
23.9*Consent of KMPG LLP related to the Midstream Assets of Eagle Rock Energy Partners, L.P.
31.1*Certification of President (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**Certification of President (Principal Executive Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**Certification Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*Report of Independent Registered Public Accounting Firm — Ernst & Young LLP opinion on consolidated financial statements of Sunoco Logistics Partners LP.
99.2*Report of Independent Registered Public Accounting Firm — Ernst & Young LLP opinion on consolidated financial statements of Susser Holdings Corporation.
99.3*Report of Independent Registered Public Accounting Firm — Ernst & Young LLP opinion on consolidated financial statements of Sunoco LP.
99.4Audited financial statements of RIGS Haynesville Partnership Co. as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 (incorporated by reference to Exhibit 99.2 of Regency Energy Partners LP Form 10-K, File No 1-35262, filed February 27, 2015)
99.5Audited financial statements of Midcontinent Express Pipeline LLC as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 (incorporated by reference to Exhibit 99.3 of Regency Energy Partners LP Form 10-K, File No. 1-35262, filed February 27, 2015)
99.6Audited financial statements of the Midstream Assets of Eagle Rock Energy Partners, L.P. as of December 31, 2013 and December 21, 2012 and for the three years ended December 31, 2013 (incorporated by reference to Exhibit 99.5 of Regency Energy Partners LP Form 10-K, File No. 1-35262, filed February 26, 2015)
99.7Statement of Policies Relating to Potential Conflicts among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and Regency Energy Partners LP dated as of April 26, 2011 (incorporated by reference to Exhibit 99.1 of Form 10-Q, file No. 1-32740, filed August 8, 2011)
101*Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2014 and December 31, 2013; (ii) our Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012; (iii) our Consolidated Statements of Comprehensive Income for years ended December 31, 2014, 2013 and 2012; (iv) our Consolidated Statement of Equity for the years ended December 31, 2014, 2013 and 2012; and (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012.
*Filed herewith.
**Furnished herewith.
+Denotes a management contract or compensatory plan or arrangement.

E- 6

INDEX TO FINANCIAL STATEMENTS
Energy Transfer Equity, L.P. and Subsidiaries
 
 Page
Report of Independent Registered Public Accounting Firm
F - 2
  
Consolidated Balance Sheets
F - 3
  
Consolidated Statements of Operations
F - 5
  
Consolidated Statements of Comprehensive Income
F - 6
  
Consolidated Statements of Equity
F - 7
  
Consolidated Statements of Cash Flows
F - 89
  
Notes to Consolidated Financial Statements
F - 911
  



F - 1


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners
Board of Directors of LE GP, LLC and
Unitholders of Energy Transfer Equity, L.P.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 20142017 and 2013, and2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are2017, and the responsibility ofrelated notes (collectively referred to as the Partnership’s management. Our responsibility is to express an“financial statements”). In our opinion, on these financial statements based on our audits. We did not audit the financial statements of Sunoco LP and Susser Holdings Corporation, both consolidated subsidiaries, as of December 31, 2014 and for the period from September 1, 2014 to December 31, 2014, whose combined statements reflect total assets constituting 7 percent of consolidated total assets as of December 31, 2014, and total revenues of 5 percent of consolidated total revenues for the year then ended. Those statements were audited by other auditors, whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco LP and Susser Holdings Corporation, is based solely on the reports of the other auditors. We did not audit the financial statements of Sunoco Logistics Partners L.P., a consolidated subsidiary, for the period from October 5, 2012 to December 31, 2012, which statements reflect revenues of 19 percent of consolidated total revenues for the year ended December 31, 2012. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco Logistics Partners L.P. for the period from October 5, 2012 to December 31, 2012, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Equity, L.P. and subsidiariesthe Partnership as of December 31, 20142017 and 2013,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20142017, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2014,2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”), and our report dated March 2, 2015February 23, 2018 expressed an unqualified opinion thereon.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP
Dallas, Texas
March 2, 2015We have served as the Partnership’s auditor since 2004.


Dallas, Texas
February 23, 2018


F - 2

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 
 December 31,
 2014 2013
ASSETS   
CURRENT ASSETS:   
Cash and cash equivalents$847
 $590
Accounts receivable, net3,378
 3,658
Accounts receivable from related companies35
 63
Inventories1,467
 1,807
Exchanges receivable44
 67
Price risk management assets81
 39
Other current assets301
 312
Total current assets6,153
 6,536
    
PROPERTY, PLANT AND EQUIPMENT45,018
 33,917
ACCUMULATED DEPRECIATION AND DEPLETION(4,726) (3,235)
 40,292
 30,682
    
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES3,659
 4,014
NON-CURRENT PRICE RISK MANAGEMENT ASSETS10
 18
GOODWILL7,865
 5,894
INTANGIBLE ASSETS, net5,582
 2,264
OTHER NON-CURRENT ASSETS, net908
 922
Total assets$64,469
 $50,330
 December 31,
 2017 2016*
ASSETS   
Current assets:   
Cash and cash equivalents$336
 $467
Accounts receivable, net4,504
 3,557
Accounts receivable from related companies53
 47
Inventories2,022
 2,055
Income taxes receivable136
 128
Derivative assets24
 21
Other current assets295
 447
Current assets held for sale3,313
 177
Total current assets10,683
 6,899
    
Property, plant and equipment71,177
 61,562
Accumulated depreciation and depletion(10,089) (7,984)
 61,088
 53,578
    
Advances to and investments in unconsolidated affiliates2,705
 3,040
Other non-current assets, net886
 815
Intangible assets, net6,116
 5,512
Goodwill4,768
 5,670
Non-current assets held for sale—
 3,411
Total assets$86,246
 $78,925
* As adjusted. See Note 2.

 





















The accompanying notes are an integral part of these consolidated financial statements.
F - 3

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 
 December 31,
 2014 2013
LIABILITIES AND EQUITY   
CURRENT LIABILITIES:   
Accounts payable$3,349
 $3,834
Accounts payable to related companies19
 14
Exchanges payable184
 284
Price risk management liabilities21
 53
Accrued and other current liabilities2,201
 1,678
Current maturities of long-term debt1,008
 637
Total current liabilities6,782
 6,500
    
LONG-TERM DEBT, less current maturities29,653
 22,562
DEFERRED INCOME TAXES4,325
 3,865
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES154
 73
OTHER NON-CURRENT LIABILITIES1,193
 1,019
    
COMMITMENTS AND CONTINGENCIES (Note 12)

 

    
REDEEMABLE NONCONTROLLING INTERESTS15
 —
PREFERRED UNITS OF SUBSIDIARY (Note 7)33
 32
    
EQUITY:   
General Partner(1) (3)
Limited Partners:   
Common Unitholders (538,766,899 and 559,923,300 units authorized, issued and outstanding as of December 31, 2014 and 2013, respectively)648
 1,066
Class D Units (1,540,000 units authorized, issued and outstanding)22
 6
Accumulated other comprehensive income (loss)(5) 9
Total partners’ capital664
 1,078
Noncontrolling interest21,650
 15,201
Total equity22,314
 16,279
Total liabilities and equity$64,469
 $50,330
 December 31,
 2017 2016*
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable$4,685
 $3,502
Accounts payable to related companies31
 42
Derivative liabilities111
 172
Accrued and other current liabilities2,582
 2,367
Current maturities of long-term debt413
 1,194
Current liabilities held for sale75
 —
Total current liabilities7,897
 7,277
    
Long-term debt, less current maturities43,671
 42,608
Long-term notes payable - related company—
 250
Deferred income taxes3,315
 5,112
Non-current derivative liabilities145
 76
Other non-current liabilities1,217
 1,075
Liabilities associated with assets held for sale—
 48
    
Commitments and contingencies

 

Preferred units of subsidiary (Note 7)—
 33
Redeemable noncontrolling interests21
 15
    
Equity:   
General Partner(3) (3)
Limited Partners:   
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)(1,643) (1,871)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)450
 180
Accumulated other comprehensive loss—
 —
Total partners’ deficit(1,196) (1,694)
Noncontrolling interest31,176
 24,125
Total equity29,980
 22,431
Total liabilities and equity$86,246
 $78,925
* As adjusted. See Note 2.











The accompanying notes are an integral part of these consolidated financial statements.
F - 4

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
 
 Years Ended December 31,
 2014 2013 2012
REVENUES:     
Natural gas sales$5,386
 $3,842
 $2,705
NGL sales5,845
 3,618
 2,253
Crude sales16,416
 15,477
 2,872
Gathering, transportation and other fees3,733
 3,097
 2,386
Refined product sales19,437
 18,479
 5,299
Other4,874
 3,822
 1,449
Total revenues55,691
 48,335
 16,964
COSTS AND EXPENSES:     
Cost of products sold48,389
 42,554
 13,088
Operating expenses2,127
 1,695
 1,118
Depreciation, depletion and amortization1,724
 1,313
 871
Selling, general and administrative611
 533
 527
Goodwill impairments370
 689
 —
Total costs and expenses53,221
 46,784
 15,604
OPERATING INCOME2,470
 1,551
 1,360
OTHER INCOME (EXPENSE):     
Interest expense, net of interest capitalized(1,369) (1,221) (1,018)
Bridge loan related fees—
 —
 (62)
Equity in earnings of unconsolidated affiliates332
 236
 212
Gain on deconsolidation of Propane Business—
 —
 1,057
Gain on sale of AmeriGas common units177
 87
 —
Losses on extinguishments of debt(25) (162) (123)
Gains (losses) on interest rate derivatives(157) 53
 (19)
Non-operating environmental remediation—
 (168) —
Other, net(11) (1) 30
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE1,417
 375
 1,437
Income tax expense from continuing operations357
 93
 54
INCOME FROM CONTINUING OPERATIONS1,060
 282
 1,383
Income (loss) from discontinued operations64
 33
 (109)
NET INCOME1,124
 315
 1,274
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST491
 119
 970
NET INCOME ATTRIBUTABLE TO PARTNERS633
 196
 304
GENERAL PARTNER’S INTEREST IN NET INCOME2
 —
 2
CLASS D UNITHOLDER’S INTEREST IN NET INCOME2
 —
 —
LIMITED PARTNERS’ INTEREST IN NET INCOME$629
 $196
 $302
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:     
Basic$1.15
 $0.33
 $0.59
Diluted$1.14
 $0.33
 $0.59
NET INCOME PER LIMITED PARTNER UNIT:     
Basic$1.16
 $0.35
 $0.57
Diluted$1.15
 $0.35
 $0.57

The accompanying notes are an integral part of these consolidated financial statements.
 Years Ended December 31,
 2017 2016* 2015*
REVENUES:     
Natural gas sales$4,172
 $3,619
 $3,671
NGL sales6,972
 4,841
 3,935
Crude sales10,184
 6,766
 8,378
Gathering, transportation and other fees4,435
 4,172
 4,200
Refined product sales11,975
 10,097
 11,321
Other2,785
 2,297
 4,591
Total revenues40,523
 31,792
 36,096
COSTS AND EXPENSES:     
Cost of products sold30,966
 23,693
 28,668
Operating expenses2,644
 2,307
 2,303
Depreciation, depletion and amortization2,554
 2,216
 1,951
Selling, general and administrative607
 693
 548
Impairment losses1,039
 1,040
 339
Total costs and expenses37,810
 29,949
 33,809
OPERATING INCOME2,713
 1,843
 2,287
OTHER INCOME (EXPENSE):     
Interest expense, net(1,922) (1,804) (1,622)
Equity in earnings from unconsolidated affiliates144
 270
 276
Impairment of investments in unconsolidated affiliates(313) (308) —
Gains on acquisitions—
 83
 —
Losses on extinguishments of debt(89) —
 (43)
Losses on interest rate derivatives(37) (12) (18)
Other, net214
 132
 20
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX BENEFIT710
 204
 900
Income tax benefit from continuing operations(1,833) (258) (123)
INCOME FROM CONTINUING OPERATIONS2,543
 462
 1,023
Income (loss) from discontinued operations, net of income taxes(177) (462) 38
NET INCOME2,366
 —
 1,061
Less: Net income (loss) attributable to noncontrolling interest1,412
 (995) (128)
NET INCOME ATTRIBUTABLE TO PARTNERS954
 995
 1,189
General Partner’s interest in net income2
 3
 3
Convertible Unitholders’ interest in net income37
 9
 —
Class D Unitholder’s interest in net income—
 —
 3
Limited Partners’ interest in net income$915
 $983
 $1,183
INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT:     
Basic$0.86
 $0.95
 $1.11
Diluted$0.84
 $0.93
 $1.11
NET INCOME PER LIMITED PARTNER UNIT:     
Basic$0.85
 $0.94
 $1.11
Diluted$0.83
 $0.92
 $1.11
F - 5* As adjusted. See Note 2.


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
 
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016* 2015*
Net income$1,124
 $315
 $1,274
$2,366
 $—
 $1,061
Other comprehensive income (loss), net of tax:          
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges3
 (4) (17)
Change in value of derivative instruments accounted for as cash flow hedges—
 (1) 12
Change in value of available-for-sale securities1
 2
 —
6
 2
 (3)
Actuarial gain (loss) relating to pension and other postretirement benefits(113) 66
 (10)(12) (1) 65
Foreign currency translation adjustment(2) (1) —
—
 (1) (1)
Change in other comprehensive income from unconsolidated affiliates(6) 17
 (9)
Change in other comprehensive income (loss) from unconsolidated affiliates1
 4
 (1)
(117) 79
 (24)(5) 4
 60
Comprehensive income1,007
 394
 1,250
2,361
 4
 1,121
Less: Comprehensive income attributable to noncontrolling interest388
 181
 959
Less: Comprehensive income (loss) attributable to noncontrolling interest1,407
 (991) (68)
Comprehensive income attributable to partners$619
 $213
 $291
$954
 $995
 $1,189
* As adjusted. See Note 2.




































The accompanying notes are an integral part of these consolidated financial statements.
F - 6

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
 
General
Partner
 
Common
Unitholders
 Class D Units 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-
controlling
Interest
 Total
Balance, December 31, 2011$—
 $52
 $—
 $1
 $7,335
 $7,388
Distributions to partners(2) (664) —
 —
 —
 (666)
Distributions to noncontrolling interest—
 —
 —
 —
 (1,017) (1,017)
Units issued in Southern Union Merger (See Note 3)—
 2,354
 —
 —
 —
 2,354
Subsidiary equity offerings, net of issue costs—
 33
 —
 —
 1,070
 1,103
Subsidiary units issued in acquisition—
 47
 —
 —
 2,248
 2,295
Non-cash compensation expense, net of units tendered by employees for tax withholdings—
 1
 —
 —
 31
 32
Capital contributions received from noncontrolling interest—
 —
 —
 —
 42
 42
ETP Holdco Transaction (see Note 3)—
 —
 —
 —
 3,580
 3,580
Other, net—
 —
 —
 —
 (11) (11)
Other comprehensive loss, net of tax—
 —
 —
 (13) (11) (24)
Net income2
 302
 —
 —
 970
 1,274
Balance, December 31, 2012—
 2,125
 —
 (12) 14,237
 16,350
Distributions to partners(2) (731) —
 —
 —
 (733)
Distributions to noncontrolling interest—
 —
 —
 —
 (1,428) (1,428)
Subsidiary equity offerings, net of issue costs—
 122
 —
 —
 1,637
 1,759
Subsidiary units issued in acquisition(1) (506) —
 —
 507
 —
Non-cash compensation expense, net of units tendered by employees for tax withholdings—
 1
 6
 —
 47
 54
Capital contributions received from noncontrolling interest—
 —
 —
 —
 18
 18
Other, net—
 —
 —
 4
 (39) (35)
Conversion of Regency Preferred Units for Regency Common Units—
 —
 —
 —
 41
 41
Deemed distribution related to SUGS Transaction—
 (141) —
 —
 —
 (141)
Other comprehensive income, net of tax—
 —
 —
 17
 62
 79
Net income—
 196
 —
 —
 119
 315
Balance, December 31, 2013(3) 1,066
 6
 9
 15,201
 16,279
Distributions to partners(2) (817) (2) —
 —
 (821)
Distributions to noncontrolling interest—
 —
 —
 —
 (1,905) (1,905)
Subsidiary units issued for cash—
 148
 2
 —
 2,907
 3,057
Subsidiary units issued in certain acquisitions—
 211
 —
 —
 5,604
 5,815
Subsidiary units redeemed in Lake Charles LNG Transaction2
 480
 —
 —
 (482) —
Purchase of additional Regency Units—
 (99) —
 —
 99
 —
Subsidiary acquisition of a noncontrolling interest—
 —
 —
 —
 (319) (319)
Non-cash compensation expense, net of units tendered by employees for tax withholdings—
 —
 14
 —
 51
 65
Capital contributions received from noncontrolling interest—
 —
 —
 —
 139
 139
Other, net—
 30
 —
 —
 (33) (3)
Units repurchased under buyback program—
 (1,000) —
 —
 —
 (1,000)
Other comprehensive loss, net of tax—
 —
 —
 (14) (103) (117)
Net income2
 629
 2
 —
 491
 1,124
Balance, December 31, 2014$(1) $648
 $22
 $(5) $21,650
 $22,314
 
General
Partner
 
Common
Unitholders
 Class D Units Series A Convertible Preferred Units 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-
controlling
Interest
 Total
Balance, December 31, 2014*(1) 648
 22
 —
 (5) 21,637
 22,301
Distributions to partners(3) (1,084) (3) —
 —
 —
 (1,090)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 (2,335) (2,335)
Subsidiary units issued(1) (524) (1) —
 —
 4,415
 3,889
Conversion of Class D Units to ETE Common Units—
 7
 (7) —
 —
 —
 —
Non-cash compensation expense, net of units tendered by employees for tax withholdings—
 —
 8
 —
 —
 62
 70
Capital contributions received from noncontrolling interest—
 —
 —
 —
 —
 875
 875
Units repurchased under buyback program—
 (1,064) —
 —
 —
 —
 (1,064)
Acquisition and disposition of noncontrolling interest—
 —
 —
 —
 —
 (65) (65)
Other comprehensive income, net of tax—
 —
 —
 —
 5
 55
 60
Other, net—
 (118) —
 —
 —
 (31) (149)
Net income (loss)3
 1,183
 3
 —
 —
 (128) 1,061
Balance, December 31, 2015*(2) (952) 22
 —
 —
 24,485
 23,553
Distributions to partners(3) (1,019) —
 —
 —
 —
 (1,022)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 (2,795) (2,795)
Distributions reinvested—
 (173) —
 173
 —
 —
 —
Subsidiary units issued for cash—
 —
 —
 —
 —
 2,559
 2,559
Subsidiary units issued for acquisition—
 —
 —
 —
 —
 307
 307
Issuance of common units—
 39
 

 (2) —
 —
 37
Non-cash compensation expense, net of units tendered by employees for tax withholdings—
 —
 (22) —
 —
 74
 52
Capital contributions received from noncontrolling interest—
 —
 —
 —
 —
 236
 236
Acquisition and disposition of noncontrolling interest—
 (779) —
 —
 —
 —
 (779)
PennTex Acquisition—
 —
 —
 —
 —
 236
 236
Other comprehensive income, net of tax—
 —
 —
 —
 —
 4
 4
Other, net(1) 30
 —
 —
 —
 14
 43
Net income (loss)3
 983
 —
 9
 —
 (995) —
Balance, December 31, 2016*$(3) $(1,871) $—
 $180
 $—
 $24,125
 $22,431
Distributions to partners(2) (1,008) —
 —
 —
 —
 (1,010)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 (2,999) (2,999)
Distributions reinvested—
 (234) —
 234
 —
 —
 —
Units issuance—
 568
 —
 —
 —
 —
 568
Subsidiary units issued for cash—
 (55) —
 (1) —
 3,291
 3,235
Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings—
 —
 —
 —
 —
 86
 86
Capital contributions received from noncontrolling interest—
 —
 —
 —
 —
 2,202
 2,202
Other, net—
 —
 —
 —
 —
 (92) (92)

The accompanying notes are an integral part of these consolidated financial statements.
F - 7
PennTex unit acquisition—
 (2) —
 —
 —
 (278) (280)
Sale of Bakken Pipeline interest—
 42
 —
 —
 —
 1,958
 2,000
Sale of Rover Pipeline interest—
 2
 —
 —
 —
 1,476
 1,478
Other comprehensive loss, net of tax—
 —
 —
 —
 —
 (5) (5)
Net income2
 915
 —
 37
 —
 1,412
 2,366
Balance, December 31, 2017$(3) $(1,643) $—
 $450
 $—
 $31,176
 $29,980
* As adjusted. See Note 2.

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016* 2015*
CASH FLOWS FROM OPERATING ACTIVITIES:     
OPERATING ACTIVITIES:     
Net income$1,124
 $315
 $1,274
$2,366
 $—
 $1,061
Reconciliation of net income to net cash provided by operating activities:          
Loss (income) from discontinued operations177
 462
 (38)
Depreciation, depletion and amortization1,724
 1,313
 871
2,554
 2,216
 1,951
Deferred income taxes(50) 43
 51
(1,871) (177) 239
Amortization included in interest expense(51) (55) (13)24
 3
 (21)
Bridge loan related fees—
 —
 62
Non-cash compensation expense82
 61
 47
Goodwill impairment370
 689
 —
Gain on sale of AmeriGas common units(177) (87) —
Gain on deconsolidation of Propane Business—
 —
 (1,057)
Gain on curtailment of other postretirement benefit plans—
 —
 (15)
Unit-based compensation expense99
 70
 91
Impairment losses1,039
 1,040
 339
Gains on acquisitions—
 (83) —
Losses on extinguishments of debt25
 162
 123
89
 —
 43
(Gains) losses on disposal of assets(1) 2
 4
Impairment of investments in unconsolidated affiliates313
 308
 —
Losses on disposal of assets—
 —
 (6)
Equity in earnings of unconsolidated affiliates(332) (236) (212)(144) (270) (276)
Distributions from unconsolidated affiliates291
 313
 208
297
 268
 409
Inventory valuation adjustments473
 (3) 75
(24) (97) 67
Other non-cash(72) 51
 211
(298) (239) (8)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 2)(231) (149) (551)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations(192) (179) (872)
Net cash provided by operating activities3,175
 2,419
 1,078
4,429
 3,322
 2,979
CASH FLOWS FROM INVESTING ACTIVITIES:     
Cash paid for Southern Union Merger, net of cash received (See Note 3)—
 —
 (2,972)
Cash paid for all other acquisitions(2,367) (405) (10)
Cash proceeds from contribution and sale of propane operations—
 —
 1,443
Cash proceeds from the sale of AmeriGas common units814
 346
 —
Proceeds from the sale of discontinued operations77
 1,008
 207
Proceeds from the sale of other assets62
 89
 44
Capital expenditures (excluding allowance for equity funds used during construction)(5,381) (3,505) (3,271)
INVESTING ACTIVITIES:     
Proceeds from sale of Bakken Pipeline interest2,000
 —
 —
Proceeds from sale of Rover Pipeline interest1,478
 —
 —
Cash paid for acquisition of PennTex noncontrolling interest(280) —
 —
Proceeds from sale of noncontrolling interest—
 —
 64
Cash paid for acquisitions, net of cash received(303) (1,398) (777)
Cash paid for acquisition of a noncontrolling interest—
 —
 (129)
Capital expenditures, excluding allowance for equity funds used during construction(8,444) (7,771) (9,073)
Contributions in aid of construction costs45
 52
 35
31
 71
 80
Contributions to unconsolidated affiliates(334) (3) (37)(268) (68) (45)
Distributions from unconsolidated affiliates in excess of cumulative earnings136
 419
 189
135
 135
 128
Proceeds from the sale of other assets48
 35
 14
Change in restricted cash172
 (348) 5
—
 14
 19
Other(19) —
 171
(3) —
 (16)
Net cash used in investing activities(6,795) (2,347) (4,196)(5,606) (8,982) (9,735)
CASH FLOWS FROM FINANCING ACTIVITIES:     
FINANCING ACTIVITIES:     
Proceeds from borrowings18,375
 12,934
 12,870
31,608
 25,785
 26,455
Repayments of long-term debt(13,886) (11,951) (8,848)(31,268) (19,076) (19,828)
Subsidiary equity offerings, net of issue costs3,057
 1,759
 1,103
Cash received from affiliate notes—
 5,317
 —
Cash paid on affiliate notes(255) (5,051) —
Units issued for cash568
 —
 —
Subsidiary units issued for cash3,235
 2,559
 3,889
Distributions to partners(821) (733) (666)(1,010) (1,022) (1,090)
Distributions to noncontrolling interests(1,905) (1,428) (1,017)(2,961) (2,766) (2,335)
Redemption of ETP Convertible Preferred Units(53) —
 —
Debt issuance costs(77) (87) (112)(131) (52) (75)
Capital contributions received from noncontrolling interest139
 18
 42
Redemption of Preferred Units—
 (340) —
Capital contributions from noncontrolling interest1,214
 236
 841
Units repurchased under buyback program(1,000) —
 —
—
 —
 (1,064)
Other, net(5) (26) (8)6
 (3) (8)
Net cash provided by financing activities3,877
 146
 3,364
953
 5,927
 6,785
INCREASE IN CASH AND CASH EQUIVALENTS257
 218
 246
CASH AND CASH EQUIVALENTS, beginning of period590
 372
 126
CASH AND CASH EQUIVALENTS, end of period$847
 $590
 $372
DISCONTINUED OPERATIONS     
Operating activities136
 93
 90
Investing activities(38) (483) (360)

The accompanying notes are an integral part of these consolidated financial statements.
F - 8
Changes in cash included in current assets held for sale(5) 5
 (13)
Net increase (decrease) in cash and cash equivalents of discontinued operations93
 (385) (283)
Decrease in cash and cash equivalents(131) (118) (254)
Cash and cash equivalents, beginning of period467
 585
 839
Cash and cash equivalents, end of period$336
 $467
 $585
* As adjusted. See Note 2.

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)

1.
OPERATIONS AND ORGANIZATION:
Financial Statement Presentation
The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2014, 20132017, 2016, and 2012,2015, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. Management has evaluated subsequent events through
Unless the date the financial statements were issued.
As discussed in Note 9, in January 2014, the Partnership completed a two-for-one split of ETE Common Units. Allcontext requires otherwise, references to unit“we,” “us,” “our,” the “Partnership” and per unit amounts in the“ETE” mean Energy Transfer Equity, L.P. and its consolidated financial statementssubsidiaries, which include ETP, ETP GP, ETP LLC, Panhandle, Sunoco LP and in these notesLake Charles LNG. References to the consolidated financial statements have been adjusted to reflect the effect of the unit split for all periods presented.
At December 31, 2014, our equity interests in Regency and ETP consisted of 100% of the respective general partner interest and IDRs, as well as the following:
 ETP Regency
Units held by wholly-owned subsidiaries:   
Common units30.8 57.2
ETP Class H units50.2 —
Units held by less than wholly-owned subsidiaries:   
Common units— 31.4
Regency Class F units— 6.3
“Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis.
The consolidated financial statements of ETE presented herein include the results of operations of:
the Parent Company;
our controlled subsidiaries, ETP and Regency (see descriptionSunoco LP;
consolidated subsidiaries of their respective operations below under “Business Operations”);
ETP’s and Regency’s consolidatedour controlled subsidiaries and our wholly-owned subsidiaries that own the general partner interests and IDR interests in ETP and Regency;Sunoco LP; and
our wholly-owned subsidiary, Lake Charles LNG. Lake Charles LNG was acquired from ETP in February 2014.
Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities.
CertainAt January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.
As discussed in Note 8, in July 2015, the Partnership completed a two-for-one split of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effects of the unit split for all periods presented.
In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior period amountsto the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled.
In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. For purposes of maintaining clarity, the following references are used herein:
References to “ETLP” refer to the entity named Energy Transfer, LP subsequent to the close of the merger;

References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and
References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.
The historical common units for ETP presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
For prior periods herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to conform to the 2014 presentation.operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.
Unless the context requires otherwise, references Additionally, for prior periods herein, certain balances have been reclassified to “we,” “us,” “our,” the “Partnership”assets and “ETE” mean Energy Transfer Equity, L.P.liabilities held for sale and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, ETE Common Holdings, LLC, Regency, Regency GP, Regency LLC, Panhandle (or Southern Union priorcertain revenues and expenses to its merger into Panhandle in January 2014), Sunoco, Inc., Sunoco Logistics, Sunoco LP, Susser and ETP Holdco. References to the “Parent Company” mean Energy Transfer Equity, L.P.discontinued operations. These reclassifications had no impact on a stand-alone basis.
In 2014, our consolidated subsidiaries, Trunkline LNG Company, LLC, Trunkline LNG Export, LLC and Susser Petroleum Partners LP, changed their names to Lake Charles LNG Company, LLC, Lake Charles LNG Export, LLC and Sunoco LP,

F - 9

respectively. All references to these subsidiaries throughout this document reflect the new names of those subsidiaries, regardless of whether the disclosure relates to periodsnet income or events prior to the dates of the name changes.total equity.
Business Operations
The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Regency.Sunoco LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 1817 for stand-alone financial information apart from that of the consolidated partnership information included herein.
Our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities are primarily conducted through our operating subsidiariesof the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as follows:a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
ETP is a publicly traded partnership whose operations are conducted throughcomprise the following subsidiaries:following:
ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through its Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through its Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.
ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:
Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.
ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.
CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus Corp., which owns 100% of the FGT interstate natural gas pipeline.
ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.
ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle and Sunoco, Inc. operations are described as follows:
Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. As discussed in Note 3, in January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger.
Sunoco, Inc. owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, ETP combined certain Sunoco, Inc. retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and Sunoco, Inc.

F - 10

Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets.
ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 42.8% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas and Louisiana and other commercial customers. As discussed in Note 3, in October 2014, Sunoco LP acquired MACS from ETP.
Regency is a publicly traded partnership engaged in the gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; the gathering and disposing of salt water; natural gas, and NGL marketing and trading; and the management of coal and natural resource properties in the United States. Regency providesfocusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales;
intrastate transportation and Granite Wash shales. Its assetsstorage natural gas operations that own and operate natural gas pipeline systems that are locatedengaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, Arkansas, West Virginia, Pennsylvania, Ohio, California, Mississippi, Alabama, New Mexico and the mid-continent region ofWest Virginia;
interstate pipelines that are owned and operated, either directly or through equity method investments, that transport natural gas to various markets in the United States, which includes Kansas, ColoradoStates; and Oklahoma. Regency also holds a 30%
controlling interest in Lone Star.Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
Sunoco LP is engaged in the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites.
Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC.
Subsequent to the Lake Charles LNG Transaction in February 2014, our reportable segments changed and currently reflect the following reportable business segments: Investment in ETP; Investment in Regency; Investment in Lake Charles LNG; and Corporate and Other.
2.
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Change in Accounting Policy
During the fourth quarter of 2017, ETP elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined product and NGL associated with the legacy Sunoco Logistics business. ETP’s management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.
As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows:
 Year Ended December 31, 2016 Year Ended December 31, 2015
 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted
Consolidated Statement of Operations and Comprehensive Income:           
Cost of products sold$23,652
 $41
 $23,693
 $28,636
 $32
 $28,668
Operating income1,884
 (41) 1,843
 2,319
 (32) 2,287
Income from continuing operations before income tax benefit245
 (41) 204
 932
 (32) 900
Net income41
 (41) —
 1,093
 (32) 1,061
Net income (loss) attributable to noncontrolling interest(954) (41) (995) (96) (32) (128)
Comprehensive income45
 (41) 4
 1,153
 (32) 1,121
            
Consolidated Statements of Cash Flows:           
Net income41
 (41) —
 1,093
 (32) 1,061
Inventory valuation adjustments(267) 170
 (97) 229
 (162) 67
Net change in operating assets and liabilities (change in inventories)(50) (129) (179) (1,066) 194
 (872)
            
Consolidated Balance Sheets (at period end):           
Inventories2,141
 (86) 2,055
 1,498
 (45) 1,453
Noncontrolling interest24,211
 (86) 24,125
 24,530
 (45) 24,485
* Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 3.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill

impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual values and results could differ from those estimates.
NewRecent Accounting Pronouncements
ASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“(“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.
For future periods, ETP expects that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of its midstream agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.
We have determined that the timing and/or amount of revenue that we recognize on certain contracts associated with Sunoco LP’s operations will be impacted by the adoption of the new standard. We currently estimate the cumulative catch-up effect to Sunoco LP’s retained earnings as of January 1, 2018 to be approximately $54 million. These adjustments are primarily related to the change in recognition of dealer incentives and rebates.
ASU 2016-02
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-16
On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.
ASU 2017-12
In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for annual reportingfinancial statements issued for fiscal years, and interim periods within those fiscal

years, beginning after December 15, 2016, including interim periods within that reporting period,2018, with earlierearly adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact if any, that adopting this new accounting standard will have on our revenue recognition policies.
In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205)consolidated financial statements and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations.  Under

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ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results.  ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.related disclosures.
Revenue Recognition
Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.
Investment in ETP
Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation.sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead.
In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which ETP operate, competitive factors in the energy industry, and other issues.
Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and grosssegment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices.
ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms

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of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.

NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third partythird-party pipeline, which is when title and risk of loss pass to the customer.
In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
ETP’s retail marketing operationsInvestment in Sunoco LP
Revenues from Sunoco LP’s two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Sunoco LP may sell gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales aremotor fuel to wholesale customers on a consignmentcommission agent basis, in which we retainSunoco LP retains title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipmentSunoco LP derives other income from rental income, propane and underground storage tanks at consignment sites,lubricating oils and in some cases we own the entire siteother ancillary product and have entered into an operating lease whit the wholesale customer operating the site. In addition, our retail outlets deriveservice offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentalrentals and other ancillary product and service offerings. Some of Sunoco Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recordedLP records revenue on a net commission basis and are recognized when the product is sold and/or services are provided. Title passage generally occurs when products are shipped or delivered in accordance withrendered. Rental income from operating leases is recognized on a straight line basis over the termsterm of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
Investment in Regency
Regency earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas, NGL, condensate and salt water gathering, processing and transportation, (iii) contract compression and treating services and (iv) coal royalties. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression and contract treating services, revenue is recognized when the service is performed. For gathering and processing services, Regency receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, Regency is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, Regency earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas and NGLs at a price approximating the index price to third parties. Regency generally reports revenue gross in the consolidated statements of operations when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because Regency takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.
Regency recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. Regency does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. Regency records any differences between the actual amounts ultimately received or paid and the original estimates

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in the period they become finalized. Most lessees must make minimum monthly or annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized as other income as it is earned.lease.
Investment in Lake Charles LNG
Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal.
Regulatory Accounting – Regulatory Assets and Liabilities
ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application ofdoes not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.

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The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows:
 
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Accounts receivable$600
 $(556) $267
$(948) $(1,126) $856
Accounts receivable from related companies30
 64
 (9)24
 42
 (5)
Inventories51
 (254) (258)58
 (480) (212)
Exchanges receivable18
 (8) 14
Other current assets133
 (81) 597
38
 165
 (225)
Other non-current assets, net(6) (23) (129)84
 (148) 247
Accounts payable(850) 541
 (989)712
 1,170
 (1,070)
Accounts payable to related companies5
 (140) 92
(178) (64) 400
Exchanges payable(99) 128
 —
Accrued and other current liabilities(59) 192
 (159)(97) 89
 (697)
Other non-current liabilities(73) 147
 26
106
 106
 (241)
Price risk management assets and liabilities, net19
 (159) (3)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations$(231) $(149) $(551)
Derivative assets and liabilities, net9
 67
 75
Net change in operating assets and liabilities, net of effects of acquisitions$(192) $(179) $(872)
Non-cash investing and financing activities and supplemental cash flow information were as follows:
 
 Years Ended December 31,
 2014 2013 2012
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$643
 $226
 $420
Net gains (losses) from subsidiary common unit transactions$744
 $(384) $80
AmeriGas limited partner interest received in Propane Contribution (see Note 4)$—
 $—
 $1,123
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with Southern Union Merger (see Note 3)$—
 $—
 $2,354
Subsidiary issuance of common units in connection with certain acquisitions$—
 $—
 $2,295
Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions$4,281
 $—
 $—
Subsidiary issuances of common units in connection with the Susser Merger$908
 $—
 $—
Long-term debt assumed in PVR Acquisition$1,887
 $—
 $—
Long-term debt exchanged in Eagle Rock Midstream Acquisition$499
 $—
 $—
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$1,416
 $1,256
 $997
Cash paid for income taxes$345
 $58
 $23
 Years Ended December 31,
 2017 2016 2015
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$1,060
 $848
 $910
Net gains (losses) from subsidiary common unit transactions(56) 16
 (526)
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with the PennTex Acquisition$—
 $307
 $—
Contribution of assets from noncontrolling interest988
 —
 34
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$1,914
 $1,922
 $1,800
Cash paid for (refund of) income taxes50
 (229) 72
Accounts Receivable
Our subsidiaries assess the credit risk of their customers. Certain of our subsidiaries deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guarantee prepayment, master setoff agreement or collateral).customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific identification.customers with payment issues.

Inventories
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Inventories2017.
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil petroleum and chemical products. Natural gas held in storage isspare parts, all of which are valued at the lower of cost or marketnet realizable value utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.
Inventories consisted of the following:
 December 31,
 2014 2013
Natural gas and NGLs$392
 $577
Crude oil364
 488
Refined products392
 543
Appliances, parts and fittings and other319
 199
Total inventories$1,467
 $1,807
During the year ended December 31, 2014, the Partnership recorded write downs of $473 million on its crude oil, refined products and NGL inventories as a result of a decline in the market price of these products. The write-down was calculated based upon current replacement costs.
 December 31,
 2017 2016
Natural gas, NGLs, and refined products$1,120
 $1,141
Crude oil551
 651
Spare parts and other351
 263
Total inventories$2,022
 $2,055
ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations.
Exchanges
Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.
Other Current Assets
Other current assets consisted of the following:
December 31,December 31,
2014 20132017 2016
Deposits paid to vendors$65
 $49
$64
 $74
Deferred income taxes14
 —
Prepaid expenses and other222
 263
231
 373
Total other current assets$301
 $312
$295
 $447
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. For the Lake Charles LNG project, a portion of the management fees are capitalized. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.

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We and our subsidiaries review property,Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
In 2017, ETP recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, ETP recorded a $133 million fixed asset impairment related to its interstate transportation and storage operations primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in its midstream operations. In 2015, ETP recorded a $110 million fixed asset impairment related to its NGL and refined products transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for its reporting units during the periods presented.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our

revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Components and useful lives of property, plant and equipment were as follows:
December 31,December 31,
2014 20132017 2016
Land and improvements$1,307
 $881
$2,222
 $1,189
Buildings and improvements (1 to 45 years)1,922
 939
2,786
 2,247
Pipelines and equipment (5 to 83 years)27,149
 21,494
44,673
 36,570
Natural gas and NGL storage facilities (5 to 46 years)1,214
 1,083
1,681
 1,451
Bulk storage, equipment and facilities (2 to 83 years)4,010
 1,933
3,883
 3,701
Tanks and other equipment (5 to 40 years)58
 1,697
Retail equipment (2 to 99 years)515
 450
Vehicles (1 to 25 years)203
 156
126
 217
Right of way (20 to 83 years)2,451
 2,190
3,432
 3,349
Furniture and fixtures (2 to 25 years)59
 51
Linepack119
 118
Pad gas44
 52
Natural resources454
 —
434
 434
Other (1 to 30 years)999
 708
Other (1 to 40 years)1,029
 2,285
Construction work-in-process4,514
 2,165
10,911
 10,119
45,018
 33,917
71,177
 61,562
Less – Accumulated depreciation and depletion(4,726) (3,235)(10,089) (7,984)
Property, plant and equipment, net$40,292
 $30,682
$61,088
 $53,578
We recognized the following amounts of depreciation expense and capitalized interest expense for the periods presented:
 Years Ended December 31,
 2014 2013 2012
Depreciation expense$1,457
 $1,128
 $801
Capitalized interest, excluding AFUDC$113
 $43
 $99
 Years Ended December 31,
 2017 2016 2015
Depreciation and depletion expense$2,204
 $1,952
 $1,661
Capitalized interest286
 201
 164
Depletion expense related to Regency’s natural resources operations was $11 million for the year ended December 31, 2014. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by Regency’s own geologists. Regency’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, Regency carries out core-hole drilling activities on coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. Regency depletes timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. Regency determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves.

F - 17

Advances to and Investments in Affiliates
Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies.
Goodwill
Goodwill An impairment of an investment in an unconsolidated affiliate is tested for impairment annually or more frequently ifrecognized when circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for reporting units within ETP’s intrastate transportation and storage and midstream operations and during the fourth quarter for reporting units within ETP’s interstate transportation and storage and liquids transportation and services operations and all others, including all of Regency’s reporting units and Lake Charles LNG.
Changesa decline in the carrying amountinvestment value is other than temporary.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of goodwill were as follows:the following:
 Investment in ETP Investment in Regency Investment in Lake Charles LNG Corporate, Other and Eliminations Total
Balance, December 31, 2012$5,606
 $1,127
 $873
 $(1,172) $6,434
Goodwill acquired156
 —
 —
 —
 156
Deconsolidation of SUGS (1)
(337) —
 —
 337
 —
Goodwill impairment(689) —
 (689) 689
 (689)
Other(7) —
 —
 —
 (7)
Balance, December 31, 20134,729
 1,127
 184
 (146) 5,894
Goodwill acquired1,874
 449
 —
 —
 2,323
Lake Charles LNG Transaction (2)
(184) —
 —
 184
 —
Goodwill impairment—
 (370) —
 —
 (370)
Other—
 17
 —
 1
 18
Balance, December 31, 2014$6,419
 $1,223
 $184
 $39
 $7,865
 December 31,
 2017 2016
Regulatory assets85
 86
Deferred charges210
 217
Restricted funds192
 190
Other399
 322
Total other non-current assets, net$886
 $815
(1)
As discussed in Note 3, Regency completed its acquisition of SUGS on April 30, 2013 which was a transaction between entities under common control. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012. Therefore, the December 31, 2012 goodwill balance includes goodwill attributable to SUGS of $337 million in both segments that was correspondingly included in the elimination column. ETP deconsolidated SUGS on April 30, 2013.
(2)
As discussed in Note 3, ETP completed the transfer to ETE of Lake Charles LNG on February 19, 2014. Therefore, the December 31, 2012 and 2013 goodwill balances include goodwill attributable to Lake Charles LNG of $873 million and$184 million, respectively, in both the investment in ETP and investment in Lake Charles LNG segments that was correspondingly included in the elimination column. The transaction was effective January 1, 2014.
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. We recorded a net increaseRestricted funds primarily consisted of restricted cash held in goodwill of $1.97 billion during the year ended December 31, 2014 primarily due to the Susser Merger and PVR Acquisition where we recorded goodwill of $1.73 billion and $370 million, respectively, offset by an impairment of $370 million. The additional goodwill recorded during the years ended December 31, 2014 and 2013 is not expected to be deductible for tax purposes.our wholly-owned captive insurance companies.
During the fourth quarter of 2014, a $370 million goodwill impairment was recorded related to Regency’s Permian Basin gathering and processing operations. The decline in estimated fair value of that reporting unit was primarily driven by the significant decline in commodity prices in the fourth quarter of 2014, and the resulting impact to future commodity prices as well as increases in future estimated operations and maintenance expenses. An assessment of these factors in the fourth quarter of 2014 led to a conclusion that the estimated fair value of Regency’s Permian reporting unit was less than its carrying amount.
During the fourth quarter of 2013, ETP performed a goodwill impairment test on its Lake Charles LNG reporting unit. In accordance with GAAP, ETP performed step one of the goodwill impairment test and determined that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount, primarily due to changes related to (i) the structure

F - 18

and capitalization of the planned LNG export project at Lake Charles LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including global natural gas prices and relative spreads, as of the date of our assessment, (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export project and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility.  An assessment of these factors in the fourth quarter of 2013 led to a conclusion that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount.  ETP then applied the second step in the goodwill impairment test, allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The assets and liabilities of the reporting unit had recently been measured at fair value in 2012 as a result of the acquisition of Southern Union, and those estimated fair values had been recorded at the reporting unit through the application of “push-down” accounting. For purposes of the hypothetical purchase price allocation used in the goodwill impairment test, ETP estimated the fair value of the assets and liabilities of the reporting unit in a manner similar to the original purchase price allocation. In allocating value to the property, plant and equipment, ETP used current replacement costs adjusted for assumed depreciation. ETP also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. ETP adjusted deferred income taxes based on these estimated fair values. Based on this hypothetical purchase price allocation, estimated goodwill was $184 million, which was less than the balance of $873 million that had originally been recorded by the reporting unit through “push-down” accounting in 2012. As a result, ETP recorded a goodwill impairment of $689 million during the fourth quarter of 2013.
No other goodwill impairments were identified or recorded for our reporting units.
Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our consolidated balance sheetsThe Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:
 
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:              
Customer relationships, contracts and agreements (3 to 46 years)$5,144
 $(485) $2,135
 $(264)$6,979
 $(1,277) $6,050
 $(971)
Trade names (15 to 20 years)556
 (15) 66
 (12)
Patents (9 years)48
 (11) 48
 (6)
Other (1 to 15 years)36
 (7) 7
 (4)
Trade names (20 years)66
 (25) 66
 (22)
Patents (10 years)48
 (26) 48
 (21)
Other (5 to 20 years)28
 (14) 25
 (10)
Total amortizable intangible assets5,784
 (518) 2,256
 (286)7,121
 (1,342) 6,189
 (1,024)
Non-amortizable intangible assets:              
Trademarks316
 —
 294
 —
295
 —
 288
 —
Other42
 —
 59
 —
Total intangible assets$6,100
 $(518) $2,550
 $(286)$7,458
 $(1,342) $6,536
 $(1,024)
Aggregate amortization expense of intangibles assets was as follows:
 Years Ended December 31,
 2014 2013 2012
Reported in depreciation, depletion and amortization$219
 $120
 $70
 Years Ended December 31,
 2017 2016 2015
Reported in depreciation, depletion and amortization$344
 $264
 $290

F - 19

Estimated aggregate amortization expense of intangible assets for the next five years was as follows:
Years Ending December 31:  
2015$263
2016260
2017260
2018259
$341
2019256
338
2020336
2021319
2022287
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.

Sunoco LP performed impairment tests on their indefinite-lived intangible assets during the fourth quarter of 2017 and recognized $13 million and $4 million impairment charge on their contractual rights and liquor licenses, included in Other Non-Current Assets, netin the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded.
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consistedIn 2015, ETP recorded $24 million of intangible asset impairments related to its NGL and retail products transportation and services operations primarily due to an expected decrease in future cash flows.

Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the following:fourth quarter.
Changes in the carrying amount of goodwill were as follows:
 December 31,
 2014 2013
Unamortized financing costs (3 to 30 years)$203
 $167
Regulatory assets85
 86
Deferred charges220
 144
Restricted funds177
 378
Other223
 147
Total other non-current assets, net$908
 $922
 Investment in ETP Investment in Sunoco LP Investment in Lake Charles LNG Corporate, Other and Eliminations Total
Balance, December 31, 2015$5,428
 $1,694
 $184
 $(1,250) $6,056
Goodwill acquired428
 81
 —
 —
 509
Sunoco LP Exchange(1,289) —
 —
 1,289
 —
Goodwill impairment(670) (227) —
 —
 (897)
Other—
 2
 —
 —
 2
Balance, December 31, 20163,897
 1,550
 184
 39
 5,670
  Goodwill acquired12
 —
 —
 —
 12
  Goodwill impairment(793) (102) —
 —
 (895)
  Other(1) (18) —
 —
 (19)
Balance, December 31, 2017$3,115
 $1,430
 $184
 $39
 $4,768
Restricted fundsGoodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
During the fourth quarter of 2017, ETP recognized goodwill impairments of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations and $452 million in its all other operations primarily consisteddue to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Sunoco LP recognized goodwill impairments of restricted$387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash heldflows from the dates the goodwill was originally recorded.
During the fourth quarter of 2016, ETP recognized goodwill impairments of $638 million in its interstate transportation and storage operations and $32 million in its midstream operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. Sunoco LP recognized goodwill impairments of $641 million, of which $227 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
During the fourth quarter of 2015, ETP recognized goodwill impairments of $99 million in its interstate transportation and storage operations and $106 million in its NGL and refined products transportation and services operations primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.
The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our wholly-owned captive insurance companies.impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts recorded by Panhandle, Sunoco Logistics and ETP’s retail marketing operations. discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 20142017 and 2013,2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes itWe believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.

F - 20

Below is a schedule of AROs by segment recorded asDecember 31, 2017 and 2016, other non-current liabilities in ourETP’s consolidated balance sheets:sheets included AROs of $165 million and $170 million, respectively.
 December 31,
 2014 2013
Investment in ETP:   
Interstate transportation and storage operations$58
 $55
Retail marketing operations87
 84
Investment in Sunoco Logistics41
 41
Investment in Regency2
 —
 $188
 $180

Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
AsLong-lived assets related to AROs aggregated to $2 million and $14 million, and were reflected as property, plant and equipment on our consolidated balance sheets as of December 31, 2014, there were no2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs.AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.
All amounts recorded in our consolidated balance sheets as of December 31, 2017 and 2016 are attributable to the obligations of ETP.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
December 31,December 31,
2014 20132017 2016
Interest payable$440
 $357
$552
 $545
Customer advances and deposits103
 142
59
 72
Accrued capital expenditures673
 260
1,006
 769
Accrued wages and benefits233
 173
280
 254
Taxes payable other than income taxes236
 211
108
 201
Income taxes payable54
 4
180
 —
Deferred income taxes99
 119
Exchanges payable154
 208
Other363
 412
243
 318
Total accrued and other current liabilities$2,201
 $1,678
$2,582
 $2,367

Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Redeemable Noncontrolling Interests
The noncontrolling interest holders in one of ETP’s consolidated subsidiaries have the option to sell their interests to ETP.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheet.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 20142017 was $31.68$45.62 billion and $30.66$44.08 billion, respectively. As of December 31, 20132016, the aggregate fair value and carrying amount of

F - 21

our consolidated debt obligations was $23.97$45.05 billion and $23.20$43.80 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives, interest rate derivatives the Preferred Units, the preferred units of a subsidiary and embedded derivatives in the preferred units of a subsidiary (the “RegencyETP Convertible Preferred Units”)Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related toDuring the Regency Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. Atyear ended December 31, 2012,2017 and 2016, no transfers were made between any levels within the fair value of the Preferred Units was based predominantly on an income approach model and considered Level 3. The Preferred Units were redeemed on April 1, 2013.hierarchy.

F - 22

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 20142017 and 20132016 based on inputs used to derive their fair values:
 Fair Value Measurements  at
December 31, 2014
 
Fair Value
Total
 Level 1 Level 2 Level 3
Assets:       
Interest rate derivatives$3
 $—
 $3
 $—
Commodity derivatives:       
Condensate — Forward Swaps36
 —
 36
 —
Natural Gas:       
Basis Swaps IFERC/NYMEX19
 19
 —
 —
Swing Swaps IFERC26
 1
 25
 —
Fixed Swaps/Futures566
 541
 25
 —
Forward Physical Contracts1
 —
 1
 —
Power:       
Forwards3
 —
 3
 —
Futures4
 4
 —
 —
Natural Gas Liquids — Forwards/Swaps69
 46
 23
 —
Refined Products — Futures21
 21
 —
 —
Total commodity derivatives745
 632
 113
 —
Total assets$748
 $632
 $116
 $—
Liabilities:       
Interest rate derivatives$(155) $—
 $(155) $—
Embedded derivatives in the Regency Preferred Units(16) —
 —
 (16)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(18) (18) —
 —
Swing Swaps IFERC(25) (2) (23) —
Fixed Swaps/Futures(490) (490) —
 —
Power:       
Forwards(4) —
 (4) —
Futures(2) (2) —
 —
Natural Gas Liquids — Forwards/Swaps(32) (32) —
 —
Refined Products — Futures(7) (7) —
 —
Total commodity derivatives(578) (551) (27) —
Total liabilities$(749) $(551) $(182) $(16)

F - 23

   Fair Value Measurements at
   December 31, 2017
 
Fair Value
Total
 Level 1 Level 2
Assets:     
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX$11
 $11
 $—
Swing Swaps IFERC13
 —
 13
Fixed Swaps/Futures70
 70
 —
Forward Physical Swaps8
 —
 8
Power — Forwards23
 —
 23
Natural Gas Liquids — Forwards/Swaps193
 193
 —
Refined Products – Futures1
 1
 —
Crude – Futures2
 2
 —
Total commodity derivatives321
 277
 44
Other non-current assets21
 14
 7
Total assets$342
 $291
 $51
Liabilities:     
Interest rate derivatives$(219) $—
 $(219)
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX(24) (24) —
Swing Swaps IFERC(15) (1) (14)
Fixed Swaps/Futures(57) (57) —
Forward Physical Swaps(2) —
 (2)
Power — Forwards(22) —
 (22)
Natural Gas Liquids — Forwards/Swaps(192) (192) 

Refined Products – Futures(28) (28) —
Crude — Futures(1) (1) —
Total commodity derivatives(341) (303) (38)
Total liabilities$(560) $(303) $(257)
 Fair Value Measurements  at
December 31, 2013
 
Fair Value
Total
 Level 1 Level 2 Level 3
Assets:       
Interest rate derivatives$47
 $—
 $47
 $—
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX5
 5
 —
 —
Swing Swaps IFERC8
 1
 7
 —
Fixed Swaps/Futures203
 201
 2
 —
Natural Gas Liquids — Forwards/Swaps7
 5
 2
 —
Power — Forwards3
 —
 3
 —
Refined Products – Futures5
 5
 —
 —
Total commodity derivatives231
 217
 14
 —
Total assets$278
 $217
 $61
 $—
Liabilities:       
Interest rate derivatives$(95) $—
 $(95) $—
Embedded derivatives in the Regency Preferred Units(19) —
 —
 (19)
Commodity derivatives:       
Condensate — Forward Swaps(1) —
 (1) —
Natural Gas:       
Basis Swaps IFERC/NYMEX(4) (4) —
 —
Swing Swaps IFERC(6) —
 (6) —
Fixed Swaps/Futures(206) (201) (5) —
Forward Physical Contracts(1) —
 (1) —
Natural Gas Liquids — Forwards/Swaps(9) (5) (4) —
Power — Forwards(1) —
 (1) —
Refined Products – Futures(5) (5) —
 —
Total commodity derivatives(233) (215) (18) —
Total liabilities$(347) $(215) $(113) $(19)
At December 31, 2013, the fair value of the Lake Charles LNG reporting unit was classified as Level 3 of the fair value hierarchy due to the significance of unobservable inputs developed using company-specific information. We used the income approach to measure the fair value of the Lake Charles LNG reporting unit. Under the income approach, we calculated the fair value based on the present value of the estimated future cash flows. The discount rate used, which was an unobservable input, was based on the weighted-average cost of capital adjusted for the relevant risk associated with business-specific characteristics and the uncertainty related to the business's ability to execute on the projected cash flows.
The following table presents the material unobservable inputs used to estimate the fair value of Regency’s Preferred Units and the embedded derivatives in Regency’s Preferred Units:
Unobservable InputDecember 31, 2014
Embedded derivatives in the Regency Preferred UnitsCredit Spread4.76%
Volatility35.80%
Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in Regency’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the Regency Preferred Units. Changes in Regency’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.

F - 24

The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2014. There were no transfers between the fair value hierarchy levels during the years ended December 31, 2014 or 2013.
Balance, December 31, 2013$(19)
Net unrealized gains included in other income (expense)3
Balance, December 31, 2014$(16)
   Fair Value Measurements at
   December 31, 2016
 
Fair Value
Total
 Level 1 Level 2 Level 3
Assets:       
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX$14
 $14
 $—
 $—
Swing Swaps IFERC2
 —
 2
 —
Fixed Swaps/Futures96
 96
 —
 —
Forward Physical Contracts1
 —
 1
 —
Power:       
Forwards4
 —
 4
 —
Futures1
 1
 —
 —
Options — Calls1
 1
 —
 —
Natural Gas Liquids — Forwards/Swaps233
 233
 —
 —
Refined Products – Futures2
 2
 —
 —
Crude – Futures9
 9
 —
 —
Total commodity derivatives363
 356
 7
 —
Other non-current assets13
 8
 5
 —
Total assets$376
 $364
 $12
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in the ETP Convertible Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) 

 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids — Forwards/Swaps(273) (273) —
 —
Refined Products – Futures(23) (23) —
 —
Crude — Futures(13) (13) —
 —
Total commodity derivatives(478) (470) (8) —
Total liabilities$(672) $(470) $(201) $(1)
Contributions in Aid of Construction Cost
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs
Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

Costs and Expenses
Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by ETP’sSunoco LP’s retail marketing operationslocations where Sunoco LP holds the inventory were $2.46 billion, $2.22 billion$234 million, $243 million and $573$231 million for the years ended December 31, 2014, 20132017, 2016 and 2012,2015, respectively.
Issuances of Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiaries’ issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Taxes
ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2014, 20132017, 2016, and 2012,2015, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include Susser and ETP Holdco, which owns Sunoco, Inc.Inland Corporation, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Panhandle.Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.

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Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third partythird-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in gains“Gains (losses) on interest rate derivativesderivatives” in the consolidated statements of operations.
Unit-Based Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
Employers are required to recognize in their balance sheetsETP recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation

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(the (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Employers must recognize the changeChanges in the funded status of the plan are recorded in the year in which the change occurs throughwithin AOCI in equity or, are reflectedfor entities applying regulatory accounting, as a regulatory asset or regulatory liability for regulated entities.liability.
Allocation of Income
For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests.

3.
ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
Pending Transaction2018 Transactions
Regency MergerCDM Contribution Agreement
In January 2015,2018, ETP and Regency entered into a definitive mergercontribution agreement as amended on February 18, 2015 (the “Merger(“CDM Contribution Agreement”), with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, Regencyamong other things, ETP will mergecontribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a wholly-owned subsidiaryvalue of ETP,approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with Regency continuing as the surviving entitya value of approximately $112 million and becoming a wholly-owned subsidiary of ETP (the “Regency Merger”). At the effective time of the Regency Merger (the “Effective Time”), each Regency common unit and Class F unit will be converted into the right to receive 0.4066 ETP Common Units, plus a number of additional ETP Common Units(iii) an amount in cash equal to $0.32 per Regency common unit divided by the lesser of (i) the volume weighted average price of$1.225 billion, subject to certain adjustments. The Class B Units that ETP Common Units for the five trading days ending on the third trading day immediately preceding the Effective Time and (ii) the closing price of ETP Common Units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Regency series A preferred unitwill receive will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. The transaction is subject to other customary closing conditions including approval by Regency’s unitholders.
In addition, ETE, which owns the general partner and 100%partnership interests of USAC that will have substantially all of the incentive distribution rights and obligations of both Regency and ETP, has agreeda USAC Common Unit, except the Class B Units will not participate in distributions made prior to reduce the incentive distributions it receives from ETP by a totalone year anniversary of $320 million over a five year period. The IDR subsidythe closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will be $80 million in the first year post closing and $60 million per year for the following four years.automatically convert into one USAC Common Unit. The transaction is expected to close in the second quarterfirst half of 2015.
ETP and Regency are under common control of ETE; therefore, we expect2018, subject to account for the Regency Merger at historical cost as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements will be retrospectively adjusted to reflect consolidation of Regency beginning May 26, 2010 (the date ETE acquired Regency’s general partner).
2014 Transactions
Susser Merger
In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens ETP’s retail geographic footprint and provides synergy opportunities and a platform for future growth.customary closing conditions.
In connection with the Susser Merger,CDM Contribution Agreement, ETP acquired an indirect 100% equity interestentered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in Susser andUSA Compression GP, LLC, the general partner interestof USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million.
Sunoco LP Convenience Store and Real Estate Sale
On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven (“SEI Fuel” and together with 7-Eleven, referred to herein collectively as “Buyers”). Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.3 billion.

Sunoco LP has signed definitive agreements with a commission agent to operate the approximately 207 retail sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the previously announced transaction with 7-Eleven, Inc. Conversion of these sites to the commission agent is expected to occur in the first quarter of 2018.
On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.

The assets under the asset purchase agreement and the incentive distributionreal estate assets subject to the portfolio optimization plan comprise the retail divestment presented as discontinued operations (“Retail Divestment”).
The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale.
The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet:
 December 31, 2017 December 31, 2016
Carrying amount of assets included as part of discontinued operations:   
Accounts receivable, net$21
 $16
Inventories149
 150
Other current assets16
 11
Property and equipment, net1,851
 1,860
Goodwill796
 1,068
Intangible assets, net477
 480
Other noncurrent assets3
 3
Total assets classified as held for sale in the Consolidated Balance Sheet$3,313
 $3,588
    
Carrying amount of liabilities included as part of discontinued operations:   
Other current and noncurrent liabilities$75
 $48
Total liabilities classified as held for sale in the Consolidated Balance Sheet$75
 $48

The results of operations associated with discontinued operations are presented in the following table:
 Years Ended December 31,
 2017 2016 2015
REVENUES$6,964
 $5,712
 $6,030
      
COSTS AND EXPENSES     
Cost of products sold5,806
 4,649
 5,026
Operating expenses763
 744
 705
Depreciation, depletion and amortization34
 143
 128
Selling, general and administrative168
 114
 91
Impairment losses285
 447
 —
Total costs and expenses7,056
 6,097
 5,950
OPERATING INCOME(92) (385) 80
Interest expense, net36
 28
 21
Other, net1
 8
 (2)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE(129) (421) 61
Income tax expense48
 41
 23
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES$(177) $(462) $38
INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE$(6) $(12) $1
In connection with the classification of those assets as held-for-sale, the related goodwill was tested for impairment based on the assumed proceeds from the sale of those assets, resulting in goodwill impairment charges of $285 million recognized in 2017.
2017 Transactions
Rover Contribution Agreement
In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.
ETP and Sunoco Logistics Merger
As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger.
Permian Express Partners
In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, the Partnership contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in the Partnership’s ownership interest in PEP to approximately 88%. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance

sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
2016 Transactions
WMB Merger
On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in Sunoco LP,ETE’s filings in the Delaware lawsuit referenced above. WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court.
PennTex Acquisition
On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately 11$627 million Sunoco LP common and subordinatedin ETP units and Susser’scash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing retail operations, consisting of 630 convenience store locations.
Effective with the closing of the transaction, Susser ceased to be a publicly traded company and itsmidstream footprint in northern Louisiana. As discussed in Note 8, ETP purchased PennTex’s remaining outstanding common stock discontinued trading on the NYSE.units in June 2017.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the Susser MergerPennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet as of December 31, 2014 reflected the preliminary
The total purchase price allocations based on available information. Management is reviewing the valuation and confirming the results to determine the final purchase price allocation.

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The following table summarizes the preliminary assets acquired and liabilities assumed recognizedwas allocated as of the merger date:follows:
 Susser At November 1, 2016
Total current assets $446
 $34
Property, plant and equipment 1,069
 393
Goodwill(1)
 1,734
 177
Intangible assets 611
 446
Other non-current assets 17
 3,877
 1,050
    
Total current liabilities 377
 6
Long-term debt, less current maturities 564
 164
Deferred income taxes 488
Other non-current liabilities 39
 17
Noncontrolling interest 626
 236
 2,094
 423
Total consideration 1,783
 627
Cash received 67
 21
Total consideration, net of cash received $1,716
 $606
(1) 
None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed is being determined using various valuation techniques, including the income and market approaches.
ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2014. Our consolidated statements of operations for the year ended December 31, 2014 reflected revenue and net income related to Susser of $2.32 billion and $105 million, respectively.
No pro forma information has been presented for the Susser Merger, as the impact of this acquisition was not material in relation to our consolidated results of operations.
MACS to Sunoco LP
In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units.
Lake Charles LNG Transaction
On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). The transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG.
In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 9.

F - 28

Panhandle Merger
On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% senior notes due 2024, 8.25% senior notes due 2029 and the junior subordinated notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million Regency Common Units and 6.3 million Regency Class F Units), and ETP (2.2 million ETP Common Units). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.
Regency’s Acquisition of PVR Partners, L.P.
On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which was funded through borrowings under Regency’s revolving credit facility. The PVR Acquisition enhances Regency’s geographic diversity with a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. Regency accounted for the PVR Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million, respectively.
Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:
AssetsAt March 21, 2014
Current assets$149
Property, plant and equipment2,716
Investment in unconsolidated affiliates62
Intangible assets (average useful life of 30 years)2,717
Goodwill370
Other non-current assets18
Total assets acquired6,032
Liabilities 
Current liabilities168
Long-term debt1,788
Premium related to senior notes99
Non-current liabilities30
Total liabilities assumed2,085
Net assets acquired$3,947
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Regency’s
Sunoco Logistics’ Vitol Acquisition
In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of Eagle Rock’s Midstream Businessan integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to 100%. The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million.
On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, includingBakken Financing
In August 2016, ETP and Phillips 66 announced the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remaindercompletion of the purchase priceproject-level financing of the Bakken Pipeline. The $2.50 billion credit facility provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $2.50 billion was funded by $400outstanding under this credit facility.
Bayou Bridge
In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system.
Sunoco Retail to Sunoco LP
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million in Regency Common Units soldSunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETE, 8.2the Partnership. The transaction was effective January 1, 2016.
Sunoco LP Acquisitions
In August 2016, Sunoco LP acquired the fuels business from Emerge Energy Services LP for $171 million, Regency Common Unitsincluding tax deductible goodwill of $53 million and intangible assets of $56 million. Additionally, during 2016, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $61 million.
In October 2016, Sunoco LP completed the acquisition of a convenience store, wholesale motor fuel distribution, and commercial fuels distribution business for approximately $55 million plus inventory on hand at closing, subject to closing adjustments.
2015 Transactions
Sunoco LP
In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons of motor fuel per year to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume-weighted average price of Sunoco LP’s common units as of March 20, 2015.
In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to Eagle RockETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and borrowings under Regency’s revolving credit facility. Regency accounted for the Eagle Rock Midstream Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognizedconverted on a one-for-one basis into Sunoco LP common units on the balance sheet at their fair valuesday immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the acquisition date. This acquisition complements Regency’s core gathering and processing business and further diversifies Regency’s geographic presencetransaction. Sunoco LP subsequently contributed its interests in the Mid-Continent region, east Texas and south Texas. Our consolidated statementSusser to one of operations for the year

F - 29

ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million, respectively.its subsidiaries.
Regency’s evaluation
Effective July 1, 2015, ETE acquired 100% of the assigned fair values is ongoing. The table below represents a preliminary allocationmembership interests of Sunoco GP, the total purchase price:
AssetsAt July 1, 2014
Current assets$120
Property, plant and equipment1,295
Other non-current assets4
Goodwill(1)
49
Total assets acquired1,468
Liabilities 
Current liabilities116
Long-term debt499
Other non-current liabilities12
Total liabilities assumed627
Net assets acquired$841
(1)
None of the goodwill is expected to be deductible for tax purposes.
The fair valuesgeneral partner of the assets acquiredSunoco LP, and liabilities assumed is being determined using various valuation techniques, including the income and market approaches.
Regency’s Acquisition of Hoover Energy
On February 3, 2014, Regency completed its acquistion of certain subsidiaries of Hoover Energy for a total purchase price of $293 million, consisted of (i) 4.0 million Regency Common Units issued to Hoover Energy, (ii) $184 million in cash. and (iii) $2 million in asset retirement obligations assumed.
2013 Transactions
Sale of Southern Union’s Distribution Operations
In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allowed a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division.
In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million, subject to customary post-closing adjustments, and the assumption of $20 million of debt.
The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations.

F - 30

The following table summarizes selected financial information related to Southern Union’s distribution operations in 2013 through MGE and NEG’s sale dates in September 2013 and December 2013, respectively, and for the period from March 26, 2012 to December 31, 2012:
 Years Ended December 31,
 2013 2012
Revenue from discontinued operations$415
 $324
Net income of discontinued operations, excluding effect of taxes and overhead allocations65
 43
SUGS Contribution
On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency areSunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE. The consideration paid by Regency inIn connection with this transaction consistedETP’s 2014 acquisition of (i) the issuance of approximately 31.4Susser, ETE agreed to provide ETP a $35 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet annual IDR subsidy for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings, provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following10 years, which terminated upon the closing and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis.
ETP’s Acquisition of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP Holdco Interest
On April 30, 2013, ETP acquired ETE’s 60% interest in ETP Holdcoa $35 million annual IDR subsidy for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “ETP Holdco Acquisition”). As a result, ETP now owns 100% of ETP Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarterstwo years beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issuedended September 30, 2015.
Bakken Pipeline
In March 2015, ETE transferred 46.2 million ETP common units, for the following eight consecutive quarters. ETP controlled ETP Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.
2012 Transactions
Southern Union Merger
On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union was the surviving entityETE’s 45% interest in the mergerBakken Pipeline project, and operated as a wholly-owned subsidiary of ETE until our contribution to ETP Holdco discussed below.
Under the terms of the merger agreement, Southern Union stockholders received a total of approximately 57$879 million ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.
Citrus Acquisition
In connection with the Southern Union Merger on March 26, 2012, ETP completed its acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.2 million ETP Common Units. See Note 4 for more information regarding ETP’s equity method investment in Citrus.
Sunoco Merger
On October 5, 2012, ETP completed its merger with Sunoco, Inc. Under the terms of the merger agreement, Sunoco, Inc. shareholders received a total of approximately 55 million ETP Common Units and a total of approximately $2.6 billion in cash.

F - 31

Sunoco, Inc. generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco, Inc. also owned a 2% general partner interest, 100% of the IDRs, and 32% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco, Inc.’s interests in Sunoco Logistics were transferred to ETP.
Prior to the Sunoco Merger, on September 8, 2012, Sunoco, Inc. completed the exit from its Northeast refining operations by contributing the refining assets at its Philadelphia refinery and various commercial contracts to PES, a joint venture with The Carlyle Group, L.P. (“The Carlyle Group”). Sunoco, Inc. also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook Industrial Complex continued to support operations at the Philadelphia refinery prior to commencement of the PES joint venture. Under the terms of the joint venture agreement, The Carlyle Group contributed cash in exchange for a 67% controlling interest in PES. In exchange for contributing its Philadelphia refinery assets and various commercial contracts to the joint venture, Sunoco, Inc. retained an approximately 33% non-operating noncontrolling interest. The fair value of Sunoco, Inc.’s retained interest in PES, which was $75 million on the date on which the joint venture was formed, was determined based on the equity contributions of The Carlyle Group. Sunoco, Inc. has indemnified PES for environmental liabilities related to the Philadelphia refinery that arose from the operation of such assets prior the formation of the joint venture. The Carlyle Group will oversee day-to-day operations of PES and the refinery. JPMorgan Chase provides working capital financing to PES in the form of an asset-backed loan, supply crude oil and other feedstocks to the refinery at the time of processing and purchase certain blendstocks and all finished refined products as they are processed. Sunoco, Inc. entered into a supply contract for gasoline and diesel produced at the refinery for its retail marketing business.
ETP incurred merger related costs related to the Sunoco Merger of $28 million during the year ended December 31, 2012. Sunoco, Inc.’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco, Inc.’s net loss included in our consolidated statement of operations was approximately $14 million during October through December 2012. Sunoco Logistics’ revenue included in our consolidated statement of operations was approximately $3.11 billion during October through December 2012. Sunoco Logistics’ net income included in our consolidated statement of operations was approximately $145 million during October through December 2012.
ETP Holdco Transaction
Immediately following the closing of the Sunoco Merger, ETE contributed its interest in Southern Union into ETP Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in ETP Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco, Inc. to ETP Holdco and retained a 40% equity interest in ETP Holdco. Prior to the contribution of Sunoco, Inc. to ETP Holdco, Sunoco, Inc. contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90.730.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017.
In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class FB Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP (“of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.
Regency Merger
On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency surviving as a wholly-owned subsidiary of ETP (the “Regency Merger”). Each Regency common unit and Class F Units”). The Class Funit was converted into the right to receive 0.6186 common units of ETP. ETP issued 258.3 million ETP common units to Regency unitholders, including 23.3 million units issued to ETP subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were exchanged for Class Gconverted into corresponding new ETP Series A Convertible Preferred Units in 2013 as discussed in Note 9. Pursuant toon a stockholders agreement between ETE and ETP, ETP controlled ETP Holdco (prior to ETP’s acquisition of ETE’s 60% equity interest in ETP Holdco in 2013) and therefore, ETP consolidated ETP Holdco (including Sunoco, Inc. and Southern Union) in its financial statements subsequent to consummation ofone-for-one basis.
In connection with the ETP Holdco Transaction.
Under the terms of the ETP Holdco transaction agreement,Regency Merger, ETE agreed to relinquish its right to $210 million ofreduce the incentive distributions it receives from ETP that ETE would otherwise be entitled to receiveby a total of $320 million over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.
Summary of Assets Acquired and Liabilities Assumed
We accounteda five-year period. The IDR subsidy was $80 million for the Southern Union Merger and Sunoco Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.

F - 32

The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates:
 
Sunoco, Inc.(1)
 
Southern Union(2)
Current assets$7,312
 $556
Property, plant and equipment6,686
 6,242
Goodwill2,641
 2,497
Intangible assets1,361
 55
Investments in unconsolidated affiliates240
 2,023
Note receivable821
 —
Other assets128
 163
 19,189
 11,536
    
Current liabilities4,424
 1,348
Long-term debt obligations, less current maturities2,879
 3,120
Deferred income taxes1,762
 1,419
Other non-current liabilities769
 284
Noncontrolling interest3,580
 —
 13,414
 6,171
Total consideration5,775
 5,365
Cash received2,714
 37
Total consideration, net of cash received$3,061
 $5,328
(1)
Includes amounts recorded with respect to Sunoco Logistics.
(2)
Includes ETP’s acquisition of Citrus.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
As a result of the Southern Union Merger, we recognized $38 million of merger-related costs during the year ended December 31, 2012. Southern Union’s revenue included in our consolidated statement2015 and will total $60 million per year for the following four years.
ETP has assumed all of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statementobligations of operations was approximately $39 million since the acquisition date to December 31, 2012.
Propane Operations
On January 12, 2012, ETP contributed its propane operations, consistingRegency and Regency Energy Finance Corp., of HOLP and Titan to AmeriGas. ETP received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, ETP entered into a support agreement with AmeriGas pursuant to which ETP is obligated to provide contingent, residual support of $1.50 billion of intercompany indebtedness owed by AmeriGas towas previously a finance subsidiary that in turn supports the repayment of $1.50 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.co-obligor or parent guarantor.
Our consolidated financial statements did not reflect the Propane Business as discontinued operations due to ETP’s continuing involvement in this business through their investment in AmeriGas that was transferred to ETP as consideration for the transaction.
In June 2012, ETP sold the remainder of its retail propane operations, consisting of its cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and ETP received net proceeds of approximately $43 million.
Sale of Canyon
In October 2012, ETP sold Canyon for approximately $207 million.  The results of continuing operations of Canyon have been reclassified to loss from discontinued operations. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $132 million during the year ended December 31, 2012.  

F - 33

Pro Forma Results of Operations
The following unaudited pro forma consolidated results of operations for the years ended December 31, 2014, 2013 and 2012 are presented as if Sunoco Merger and the ETP Holdco Transaction had been completed on January 1, 2012, and the PVR and Eagle Rock Midstream acquisitions had been completed on January 1, 2013, and assumes there were no other changes in operations.
 Years Ended December 31,
 2014 2013 2012
Revenues$56,517
 $50,473
 $40,398
Net income1,098
 252
 868
Net income attributable to partners607
 133
 866
Basic net income per Limited Partner unit$1.12
 $0.24
 $1.55
Diluted net income per Limited Partner unit$1.11
 $0.24
 $1.55
The pro forma consolidated results of operations include adjustments to:
include the results of Southern Union and Sunoco, Inc. beginning January 1, 2012;
include the results of PVR and Eagle Rock midstream beginning January 1, 2013;
include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting; and
•include incremental interest expense related to the financing of a proportionate share of the purchase price.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

F - 34

4.
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
AmeriGas
As discussed in Note 3, on January 12, 2012, ETP received approximately 29.6 million AmeriGas common units in connection with the contribution of its propane operations. In the year ended 2013, ETP sold 7.5 million AmeriGas common units for net proceeds of $346 million, and in the year ended 2014, ETP sold approximately 18.9 million AmeriGas common units for net proceeds of $814 million. Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and general partnership purposes. Subsequent to the sales, ETP’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.
Citrus
On March 26, 2012, ETE consummated the acquisition of Southern Union and, concurrently with the closing of the Southern Union acquisition, CrossCountry, a subsidiary of Southern Union that indirectly owned a 50% interest in Citrus, merged with a subsidiary of ETP and, in connection therewith, ETP paid approximately $1.9 billion in cash and issued $105 million of ETP Common Units (the “Citrus Acquisition”) to a subsidiary of ETE. As a result of the consummation of the Citrus Acquisition, ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc.KMI. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
ETP recorded its investment in Citrus at $2.0 billion, which exceeded its proportionate share of Citrus’ equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting. The carrying amount of ETP’s investment in Citrus was $1.82 billion and $1.89 billion at December 31, 2014 and 2013, respectively, and was reflected in ETP’s interstate transportation and storage operations.
FEP
ETP has a 50% interest in FEP a 50/50 joint venture with Kinder Morgan, Inc. FEPwhich owns the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The carrying amount of ETP’sETP evaluated its investment in FEP was $130 million and $144 millionfor impairment as of December 31, 20142017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and 2013, respectively,Joint Ventures. ETP recorded an impairment of its investment in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and was reflected in ETP’s interstate transportation and storage operations.a customer re-contracting with a competitor.
Midcontinent Express Pipeline LLC
MEP
RegencyETP owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipelinespipeline that extendextends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. The carrying amount of Regency’sETP evaluated its investment in MEP was $695 million and $548 millionfor impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2014 and 2013, respectively, and was reflected in Regency’s natural gas transportation operations.2016.
RIGS Haynesville Partnership Co.HPC
RegencyETP owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. The carrying amount of Regency’sETP evaluated its investment in HPC was $422 million and $442 millionfor impairment as of December 31, 20142017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and 2013, respectively,Joint Ventures. During the year ended December 31, 2017, ETP recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and was reflectedcash flows driven by the bankruptcy of one of HPC’s major customers in Regency’s natural gas transportation operations.2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.

The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2017 and 2016, were as follows:
F - 35
 December 31,
 2017 2016
Citrus$1,754
 $1,729
FEP121
 101
MEP242
 318
HPC28
 382
Others560
 510
Total$2,705
 $3,040

The following table presents equity in earnings (losses) of unconsolidated affiliates:
Table of Contents

 December 31,
Equity in earnings (losses) of unconsolidated affiliates:2017 2016 2015
Citrus$144
 $102
 $97
FEP53
 51
 55
MEP38
 40
 45
HPC(1)
(168) 31
 32
Others77
 46
 47
Total$144
 $270
 $276
(1)
For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basisbasis) for all periods presented).
presented:
December 31,December 31,
2014 20132017 2016
Current assets$889
 $1,028
$206
 $214
Property, plant and equipment, net10,520
 10,778
8,336
 8,726
Other assets2,687
 2,664
43
 181
Total assets$14,096
 $14,470
$8,585
 $9,121
      
Current liabilities$1,983
 $1,039
$861
 $816
Non-current liabilities7,359
 8,139
4,492
 4,940
Equity4,754
 5,292
3,232
 3,365
Total liabilities and equity$14,096
 $14,470
$8,585
 $9,121
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Revenue$4,925
 $4,695
 $4,492
$1,358
 $1,164
 $1,385
Operating income1,071
 1,197
 863
407
 714
 800
Net income577
 699
 491
145
 384
 470
In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.



F - 36

5.
NET INCOME PER LIMITED PARTNER UNIT:
Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of ourthe ETE Series A Convertible Preferred Units, seeas discussed in Note 7.8. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or RegencySunoco LP that would have resulted assuming the incremental units related to ETP’s or Regency’sSunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method.
The calculation below for the year ended December 31, 2012 for diluted net income per limited partner unit excludes the impact of any ETE Common Units that would be issued upon conversion of the Preferred Units, because inclusion would have been antidilutive. The Preferred Units were redeemed April 1, 2013 as discussed in Note 7.
A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Income from continuing operations$1,060
 $282
 $1,383
$2,543
 $462
 $1,023
Less: Income from continuing operations attributable to noncontrolling interest434
 99
 1,070
Less: Income (loss) from continuing operations attributable to noncontrolling interest1,583
 (545) (165)
Income from continuing operations, net of noncontrolling interest626
 183
 313
960
 1,007
 1,188
Less: General Partner’s interest in income from continuing operations2
 —
 1
2
 3
 3
Less: Convertible Unitholders’ interest in net income from continuing operations38
 8
 —
Less: Class D Unitholder’s interest in income from continuing operations2
 —
 —
—
 —
 3
Income from continuing operations available to Limited Partners$622
 $183
 $312
$920
 $996
 $1,182
Basic Income from Continuing Operations per Limited Partner Unit:          
Weighted average limited partner units544.3
 560.9
 533.4
1,078.2
 1,045.5
 1,062.8
Basic income from continuing operations per Limited Partner unit$1.15
 $0.33
 $0.59
$0.86
 $0.95
 $1.11
Basic income (loss) from discontinued operations per Limited Partner unit$0.01
 $0.02
 $(0.02)$(0.01) $(0.01) $—
Diluted Income from Continuing Operations per Limited Partner Unit:          
Income from continuing operations available to Limited Partners$622
 $183
 $312
$920
 $996
 $1,182
Dilutive effect of equity-based compensation of subsidiaries and distributions to Class D Unitholder(2) —
 (1)
Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units38
 8
 3
Diluted income from continuing operations available to Limited Partners620
 183
 311
958
 1,004
 1,185
Weighted average limited partner units544.3
 560.9
 533.4
1,078.2
 1,045.5
 1,062.8
Dilutive effect of unconverted unit awards1.1
 —
 —
Dilutive effect of unconverted unit awards and Convertible Units72.6
 33.1
 1.6
Weighted average limited partner units, assuming dilutive effect of unvested unit awards545.4
 560.9
 533.4
1,150.8
 1,078.6
 1,064.4
Diluted income from continuing operations per Limited Partner unit$1.14
 $0.33
 $0.59
$0.84
 $0.93
 $1.11
Diluted income (loss) from discontinued operations per Limited Partner unit$0.01
 $0.02
 $(0.02)$(0.01) $(0.01) $—


F - 37

6.DEBT OBLIGATIONS:
Our debt obligations consist of the following:
 December 31,
 2014 2013
Parent Company Indebtedness:   
7.50% Senior Notes, due October 15, 2020$1,187
 $1,187
5.875% Senior Notes, due January 15, 20241,150
 450
ETE Senior Secured Term Loan, due December 2, 20191,400
 1,000
ETE Senior Secured Revolving Credit Facility due December 18, 2018940
 171
Unamortized premiums, discounts and fair value adjustments, net3
 (7)
 4,680
 2,801
    
Subsidiary Indebtedness:   
ETP Debt   
8.5% Senior Notes due April 15, 2014—
 292
5.95% Senior Notes due February 1, 2015750
 750
6.125% Senior Notes due February 15, 2017400
 400
6.7% Senior Notes due July 1, 2018600
 600
9.7% Senior Notes due March 15, 2019400
 400
9.0% Senior Notes due April 15, 2019450
 450
4.15% Senior Notes due October 1, 2020700
 700
4.65% Senior Notes due June 1, 2021800
 800
5.20% Senior Notes due February 1, 20221,000
 1,000
3.60% Senior Notes due February 1, 2023800
 800
4.9% Senior Notes due February 1, 2024350
 350
7.6% Senior Notes due February 1, 2024277
 277
8.25% Senior Notes due November 15, 2029267
 267
6.625% Senior Notes due October 15, 2036400
 400
7.5% Senior Notes due July 1, 2038550
 550
6.05% Senior Notes due June 1, 2041700
 700
6.5% Senior Notes due February 1, 20421,000
 1,000
5.15% Senior Notes due February 1, 2043450
 450
5.95% Senior Notes due October 1, 2043450
 450
Floating Rate Junior Subordinated Notes due November 1, 2066546
 546
ETP $2.5 billion Revolving Credit Facility due October 27, 2019570
 65
Unamortized premiums, discounts and fair value adjustments, net(1) (34)
 11,459
 11,213
    
Panhandle Debt(1)
   
6.20% Senior Notes due November 1, 2017300
 300
7.00% Senior Notes due June 15, 2018400
 400
8.125% Senior Notes due June 1, 2019150
 150
7.60% Senior Notes due February 1, 202482
 82
7.00% Senior Notes due July 15, 202966
 66
8.25% Senior Notes due November 14, 202933
 33
Floating Rate Junior Subordinated Notes due November 1, 206654
 54
Unamortized premiums, discounts and fair value adjustments, net99
 155
 1,184
 1,240
    
Regency Debt   
6.875% Senior Notes due December 1, 2018—
 600
5.75% Senior Notes due September 1, 2020400
 400
6.5% Senior Notes due July 15, 2021500
 500
5.875% Senior Notes due March 1, 2022900
 —
5.5% Senior Notes due April 15, 2023700
 700
4.5% Senior Notes due November 1, 2023600
 600
 December 31,
 2017 2016
Parent Company Indebtedness:   
7.50% Senior Notes due October 15, 2020$1,187
 $1,187
5.875% Senior Notes due January 15, 20241,150
 1,150
5.50% Senior Notes due June 1, 20271,000
 1,000
4.25% Senior Notes due March 15, 20231,000
 —
ETE Senior Secured Term Loan due December 2, 2019—
 2,190
ETE Senior Secured Term Loan due February 2, 20241,220
 —
ETE Senior Secured Revolving Credit Facility due December 18, 2018—
 875
ETE Senior Secured Revolving Credit Facility due March 24, 20221,188
 —
Unamortized premiums, discounts and fair value adjustments, net(11) (15)
Deferred debt issuance costs(34) (30)
 6,700
 6,357
    
Subsidiary Indebtedness:   
ETP Debt   
6.125% Senior Notes due February 15, 2017—
 400
2.50% Senior Notes due June 15, 2018 (1)
650
 650
6.70% Senior Notes due July 1, 2018 (1)
600
 600
9.70% Senior Notes due March 15, 2019400
 400
9.00% Senior Notes due April 15, 2019450
 450
5.50% Senior Notes due February 15, 2020250
 250
5.75% Senior Notes due September 1, 2020400
 400
4.15% Senior Notes due October 1, 20201,050
 1,050
4.40% Senior Notes due April 1, 2021600
 600
6.50% Senior Notes due July 15, 2021—
 500
4.65% Senior Notes due June 1, 2021800
 800
5.20% Senior Notes due February 1, 20221,000
 1,000
4.65% Senior Notes due February 15, 2022300
 300
5.875% Senior Notes due March 1, 2022900
 900
5.00% Senior Notes due October 1, 2022700
 700
3.45% Senior Notes due January 15, 2023350
 350
3.60% Senior Notes due February 1, 2023800
 800
5.50% Senior Notes due April 15, 2023—
 700
4.50% Senior Notes due November 1, 2023600
 600
4.90% Senior Notes due February 1, 2024350
 350
7.60% Senior Notes due February 1, 2024277
 277
4.25% Senior Notes due April 1, 2024500
 500
9.00% Debentures due November 1, 202465
 65
4.05% Senior Notes due March 15, 20251,000
 1,000
5.95% Senior Notes due December 1, 2025400
 400
4.75% Senior Notes due January 15, 20261,000
 1,000
3.90% Senior Notes due July 15, 2026550
 550
4.20% Senior Notes due April 15, 2027600
 —
4.00% Senior Notes due October 1, 2027
750
 —
8.25% Senior Notes due November 15, 2029267
 267
4.90% Senior Notes due March 15, 2035500
 500
6.625% Senior Notes due October 15, 2036400
 400
7.50% Senior Notes due July 1, 2038550
 550
6.85% Senior Notes due February 15, 2040250
 250
6.05% Senior Notes due June 1, 2041700
 700
6.50% Senior Notes due February 1, 20421,000
 1,000
6.10% Senior Notes due February 15, 2042300
 300

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8.375% Senior Notes due June 1, 2020390
 —
6.5% Senior Notes due May 15, 2021400
 —
8.375% Senior Notes due June 1, 2019499
 —
5.0% Senior Notes due October 1, 2022700
 —
Regency $1.2 billion Revolving Credit Facility due November 25, 20191,504
 510
Unamortized premiums, discounts and fair value adjustments, net48
 —
 6,641
 3,310
    
Sunoco, Inc. Debt   
4.875% Senior Notes due October 15, 2014—
 250
9.625% Senior Notes due April 15, 2015250
 250
5.75% Senior Notes due January 15, 2017400
 400
9.00% Debentures due November 1, 202465
 65
Unamortized premiums, discounts and fair value adjustments, net35
 70
 750
 1,035
    
Sunoco Logistics Debt   
8.75% Senior Notes due February 15, 2014(2)
—
 175
6.125% Senior Notes due May 15, 2016175
 175
5.50% Senior Notes due February 15, 2020250
 250
4.65% Senior Notes due February 15, 2022300
 300
3.45% Senior Notes due January 15, 2023350
 350
4.25% Senior Notes due April 1, 2024500
 —
6.85% Senior Notes due February 1, 2040250
 250
6.10% Senior Notes due February 15, 2042300
 300
4.95% Senior Notes due January 15, 2043350
 350
5.30% Senior Notes due April 1, 2044700
 —
5.35% Senior Notes due May 15, 2045800
 —
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015(3)
35
 35
Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018150
 200
Unamortized premiums, discounts and fair value adjustments, net100
 118
 4,260
 2,503
    
Sunoco LP Debt   
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019683
 —
 683
 —
    
Transwestern Debt   
5.39% Senior Notes due November 17, 2014—
 88
5.54% Senior Notes due November 17, 2016125
 125
5.64% Senior Notes due May 24, 201782
 82
5.36% Senior Notes due December 9, 2020175
 175
5.89% Senior Notes due May 24, 2022150
 150
5.66% Senior Notes due December 9, 2024175
 175
6.16% Senior Notes due May 24, 203775
 75
Unamortized premiums, discounts and fair value adjustments, net(1) (1)
 781
 869
    
Other223
 228
 30,661
 23,199
Less: current maturities1,008
 637
 $29,653
 $22,562
4.95% Senior Notes due January 15, 2043350
 350
5.15% Senior Notes due February 1, 2043450
 450
5.95% Senior Notes due October 1, 2043450
 450
5.30% Senior Notes due April 1, 2044700
 700
5.15% Senior Notes due March 15, 20451,000
 1,000
5.35% Senior Notes due May 15, 2045800
 800
6.125% Senior Notes due December 15, 20451,000
 1,000
5.30% Senior Notes due April 15, 2047900
 —
5.40% Senior Notes due October 1, 2047
1,500
 —
Floating Rate Junior Subordinated Notes due November 1, 2066546
 546
ETP $4.0 billion Revolving Credit Facility due December 20222,292
 —
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)
50
 —
ETLP $3.75 billion Revolving Credit Facility due November 2019—
 2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020—
 1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017—
 630
Unamortized premiums, discounts and fair value adjustments, net33
 66
Deferred debt issuance costs(170) (166)
 29,210
 29,454
    
Transwestern Debt   
5.64% Senior Notes due May 24, 2017—
 82
5.36% Senior Notes due December 9, 2020175
 175
5.89% Senior Notes due May 24, 2022150
 150
5.66% Senior Notes due December 9, 2024175
 175
6.16% Senior Notes due May 24, 203775
 75
Deferred debt issuance costs(1) (1)
 574
 656
    
Panhandle Debt   
6.20% Senior Notes due November 1, 2017—
 300
7.00% Senior Notes due June 15, 2018400
 400
8.125% Senior Notes due June 1, 2019150
 150
7.60% Senior Notes due February 1, 202482
 82
7.00% Senior Notes due July 15, 202966
 66
8.25% Senior Notes due November 14, 202933
 33
Floating Rate Junior Subordinated Notes due November 1, 206654
 54
Unamortized premiums, discounts and fair value adjustments, net28
 50
 813
 1,135
    
Sunoco, Inc. Debt   
5.75% Senior Notes due January 15, 2017—
 400
    
Bakken Project Debt   
Bakken Project $2.50 billion Credit Facility due August 20192,500
 1,100
Deferred debt issuance costs(8) (13)
 2,492
 1,087
PennTex Debt   
PennTex $275 million Revolving Credit Facility due December 2019—
 168
    
Sunoco LP Debt   
5.50% Senior Notes due August 1, 2020600
 600
6.375% Senior Notes due April 1, 2023800
 800
6.25% Senior Notes due April 15, 2021800
 800
Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019765
 1,000
Sunoco LP Term Loan due October 1, 20191,243
 1,243
Lease-related obligations113
 118
Deferred debt issuance costs(34) (47)
 4,287
 4,514

    
Other8
 31
Total debt44,084
 43,802
Less: current maturities of long-term debt413
 1,194
Long-term debt, less current maturities$43,671
 $42,608
(1) 
In connection withAs of December 31, 2017 ETP’s management had the Panhandle Merger, Southern Union’s debt obligations were assumed by Panhandle.intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.
(2) 
Sunoco Logistics’ 8.75% senior notes due February 15, 2014Borrowings under 364-day credit facilities were classified as long-term debt as Sunoco Logistics repaid these notes in February 2014 with borrowings under its $1.50 billion credit facility due November 2018.

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(3)
The Sunoco Logistics $35 million credit facility outstanding amounts were classified as long-term debt as Sunoco Logistics hasbased on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $283$197 million in unamortized premiums, and fair value adjustments and deferred debt issuance costs, net:
2015$1,050
2016314
20171,228
20182,095
$1,705
20195,662
5,512
20203,667
20212,205
20226,540
Thereafter20,029
24,652
Total$30,378
$44,281
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
Notes and Debentures
ETE Senior Notes Offering
In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes.
The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The balance is payable upon maturity. Interest on the senior notes is paid semi-annually.
ETE Senior Notes
The ETE Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ETE Senior Notes are secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ETE Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries.
The covenants related to the ETE Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets.
As discussed above, the Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP and Regency constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP and Regency are required under Rule 3-16 to be included in thisthe Partnership’s Annual Report on Form 10-K and have been included herein.

The Parent Company’s interests in ETP GP ETE Common Holdings, LLC, ETE GP Acquirer LLC, and Regency GP LP (collectively, the “Non-Reporting Entities”) also constituteconstitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of the Non-Reporting EntitiesETP GP would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. None of the Non-Reporting Entities hasETP GP does not have substantive operations of its own; rather, each of the Non-Reporting Entities holds only direct or indirect interests in ETP, Regency and/or the consolidated subsidiaries of ETP and Regency. Following is a summary of the interests held by each of the Non-Reporting Entities, as well as a summary of the significant differences between each of the Non-Reporting Entities compared to ETP and Regency, as applicable:
ETP GP only owns 100% of the general partner interest in ETP. ETP GP does not own limited partner interests in ETP; therefore, the limited partner interests in ETP, which had a carrying value of $11.9$28.02 billion and $11.3$18.41 billion as of December 31, 20142017 and 2013,2016, respectively, would be reflected as noncontrolling interests on ETP GP’s balance sheets. Likewise, ETP’s income (loss) attributable to limited partners (including common unitholders, and Class H unitholders)unitholders, Class I unitholders and ETP Preferred Units) of $823 million, $(50)$1.08 billion, $(660) million and $1.11 billion$325 million for the years ended December 31, 2014, 20132017, 2016 and 2012,2015, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations.
ETE Common Holdings, LLC (“ETE Common Holdings”) owns 5.2 million ETP Common Units, representing approximately 1.5% of the total outstanding ETP Common Units, and 50.2 million ETP Class H Units, representing 100% of the total outstanding ETP Class H Units. ETE Common Holdings also owns 30.9 million Regency Common

F - 40

Units, representing approximately 7.5% of the total outstanding Regency Common Units; ETE Common Holdings’ interest in Regency was acquired in 2014. ETE Common Holdings does not own the general partner interests in ETP or Regency; therefore, the financial statements of ETE Common Holdings would only reflect equity method investments in ETP and Regency. The carrying values of ETE Common Holdings’ investments in ETP and Regency were $1.72 billion and $760 million, respectively, as of December 31, 2014 and $1.66 billion and zero, respectively, as of December 31, 2013. ETE Common Holdings’ equity in earnings (losses) from its investments in ETP and Regency were $292 million and $(9) million, respectively, for the year ended December 31, 2014 and $134 million and zero, respectively, for the period from April 26, 2013 (inception of ETE Common Holdings) to December 31, 2013.
ETE GP Acquirer LLC (“ETE GP Acquirer”) owns 100% of Regency GP, which owns 100% of the general partner interest in Regency. Neither ETE GP Acquirer nor Regency GP own limited partner interests in Regency; therefore, the limited partner interests in Regency, which had a carrying value of $8.7 billion and $4.0 billion as of December 31, 2014 and 2013, respectively, would be reflected as noncontrolling interests on ETE GP Acquirer’s and Regency GP’s balance sheets. Likewise, Regency’s income (loss) attributable to limited partners and preferred unitholders, which totaled $(188) million, $8 million and $23 million for the years ended December 31, 2014, 3013 and 2012, respectively, would be reflected as income attributable to noncontrolling interest in ETE GP Acquirer’s and Regency GP’s statements of operations.
ETP’s general partner interest Common Units and Class H Units areis reflected separately in ETP’s financial statements, and Regency’s general partner interest and Common Units are reflected separately in Regency’s financial statements. As a result, the financial statements of the Non-Reporting EntitiesETP GP would substantially duplicate information that is available in the financial statements of ETP and Regency.ETP. Therefore, the financial statements of the Non-Reporting EntitiesETP GP have been excluded from thisthe Partnership’s Annual Report on Form 10-K.
ETP as Co-Obligor of Sunoco, Inc. Debt
In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $715 million as of December 31, 2014.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.26% at December 31, 2014.
ETP Senior Notes
The ETP senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.
The ETP senior notes are unsecured obligations of ETP and the obligation of ETP to repay the ETP senior notes is not guaranteed by us or any of ETP’s subsidiaries. Asas a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.
Transwestern Senior Notes
The Transwestern senior notes are payableredeemable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017.
Sunoco LogisticsLP Private Offering of Senior Notes Offerings
In April 2014,On January 23, 2018, Sunoco Logistics issued $300 millionLP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 4.25%4.875% senior notes due April 2024 and $7002023, $800 million in aggregate principal amount of 5.30%5.500% senior notes due April 2044.
In November 2014, Sunoco Logistics issued an additional $2002026 and $400 million under the April 2024 senior notes and $800 million aggregate principal amount of 5.35% senior notes due May 2045. Sunoco Logistics used the net proceeds from the offerings to pay borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes.

F - 41

Regency Senior Notes
The Regency senior notes are unsecured obligations of Regency and the obligation of Regency to repay the Regency senior notes is not guaranteed by us or any of Regency’s subsidiaries. The Regency senior notes effectively rank junior to all indebtedness and other liabilities of Regency’s existing and future subsidiaries. Interest is payable semi-annually.
In February 2014, Regency issued $900 millionin aggregate principal amount of 5.875% senior notes due March 1, 2022.
In March 2014, as part2028. Sunoco LP used the proceeds from the private offering, along with proceeds from the closing of the PVR Acquisition, Regency assumed the outstandingasset purchase agreement with 7-Eleven to: 1) redeem in full its existing senior notes as of PVR with anDecember 31, 2017, comprised of $800 million in aggregate notional amount of $1.2 billion. The PVR senior notes consisted of $300 million principal amount of 8.25% 6.250%senior notes due April 15, 2018, $4002021, $600 million in aggregate principal amount of 6.5%5.500% senior notes due May 15, 2021,2020, and $473$800 million in aggregate principal amount of 8.375%6.375% senior notes due June 1, 2020. 2023; 2) repay in full and terminate the Sunoco LP Term Loan; 3) pay all closing costs and taxes in connection with the 7-Eleven transaction; 4) redeem the outstanding Sunoco LP Series A Preferred Units as mentioned above; and 5) repurchase 17,286,859 common units owned by ETP as mentioned above.
Sunoco LP Senior Notes
In April 2014, Regency redeemed all of the $300 million principal amount of 8.25% senior notes due April 15, 2018 for $313 million in cash. In July 2014, Regency redeemed $83 million of the $473 million principal amount of 8.375% senior notes due June 1, 2020 for $91 million, including $8 million of accrued interest and redemption premium.
In July 2014, Regency exchanged $4992016, Sunoco LP issued $800 million aggregate principal amount of 8.375% senior notes6.25% Senior Notes due 20192021. The net proceeds of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% senior notes due 2019 issued by Regency and its wholly-owned subsidiary.
In July 2014, Regency issued $700$789 million aggregate principal amount of 5.0% senior notes that mature on October 1, 2022.
In December 2014, Regency redeemed allwere used to repay a portion of the outstanding $600 million senior notesborrowings under its term loan facility.
The 6.25% Senior Notes due 2018, for a total price2021 were redeemed on January 23, 2018. See Sunoco LP Private Offering of $621 million.Senior Notes above.
Term Loans, and Credit Facilities and Commercial Paper
ETE Term Loan Facility
The Parent Company hasOn February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “ETE“Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement”), whichAgreement has a scheduled maturity date of DecemberFebruary 2, 2019,2024, with an option for the Parent Company to extend the term

subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements.
Pursuant to the ETE Term Credit Agreement, the lendersTerm Lenders have provided senior secured financing in an aggregate principal amount of $1.0$2.2 billion (the “ETE Term“Term Loan Facility”). The Parent Company shallis not be required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the PartnershipParent Company is required to repayprepay the term loan in connection with dispositions of (a) incentive distribution rightsIDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics ; or Regency, (b) general partnership interests in Regency or (c) equity interests of any Personperson which owns, directly or indirectly, incentive distribution rightsIDRs in (i) prior to the consummation of the Sunoco Logistics Merger, ETP, or Regency or general partnership interests in Regency,and (ii) upon and after the consummation of the Sunoco Logistics Merger, Sunoco Logistics, in each case, yieldingwith a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million.$50 million.
Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets subject to certain exceptionsincluding (i) approximately 27.5 million common units representing limited partner interests in ETP owned by the Partnership; and permitted liens.(ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in ETP. The ETE Term Loan Facility initially is not guaranteed by any of the Parent Company’sPartnership’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, plus an applicable margin based on the election of the Parent Company for each interest period.period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.50%2.75% and the applicable margin for base rate loans is 1.50%1.75%.
In April 2014, Proceeds of the Parent Company amended its Senior Secured Term Loan Agreement (the “ETE Term Credit Agreement”) to increase the aggregate principal amount to $1.4 billion. The Parent Company used the proceeds from this $400 million increase to repay borrowings under its revolving credit facility and for general partnership purposes. No other significant changes were made to the terms of the ETE Term Credit Agreement including maturity datewere used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and interest rate.to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto.
On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%.
In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement.
ETE Revolving Credit Facility
The Parent Company hashad a revolver credit agreement (the “Revolving Credit Agreement”) which hashad a scheduled maturity date of December 2, 2018, with an option for the PartnershipParent Company to extend the term subject to the terms and conditions set forth therein. The agreement was terminated in connection with entry into the Revolver Credit Agreement, discussed below.
On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $600 million$1.50 billion at any one time outstanding, (the “ETE Revolving Credit Facility”), and the Parent Company has the option to request increases in the aggregate commitments provided that the aggregate commitments never exceed $1.0 billion. In February 2014, the Partnership increased the capacity on the ETE Revolving Credit Facilityby up to $800 million. In May 2014, the Parent Company amended its revolving credit facility to increase the capacity to $1.2 billion. In February 2015, the Parent Company amended its revolving credit facility to increase the capacity to $1.5 billion.

F - 42

$500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150$150 million sublimit.
Under the Revolver Credit Agreement, the obligations of the Parent CompanyPartnership are secured by a lien on substantially all of the Parent Company’sPartnership’s and certain of its subsidiaries’ tangible and intangible assets. Borrowings under the Revolver Credit Agreement are not guaranteed by any of the Parent Company’s subsidiaries.
Interest accrues on advances at a LIBOR rate or a base rate, plus an applicable margin based on the election of the Parent Company for each interest period.period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of December 31, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $312 million.

ETP Credit FacilityFacilities
On December 1, 2017 ETP entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).  The ETP CreditFive-Year Facility allows for borrowings ofcontains an accordion feature, under which the total aggregate commitments may be increased up to $2.5$6.0 billion and expires in October 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of ETP’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as ETP’s other current and future unsecured debt.certain conditions. ETP uses the ETP Credit FacilityFacilities to provide temporary financing for ETP’sits growth projects, as well as for general partnership purposes. In February 2015, ETP amended its revolving credit facility to increase the capacity to $3.75 billion.
As of December 31, 2014,2017, the ETP CreditFive-Year Facility had $570 million$2.29 billion outstanding, and theof which $2.01 billion was commercial paper. The amount available for future borrowings was $1.81$1.56 billion after taking into account letters of credit of $121$150 million. The weighted average interest rate on the total amount outstanding as of December 31, 20142017 was 1.66%2.48%.
Regency Credit Facility
The Regency Credit Facility has aggregate revolving commitments of $2.0 billion, with a $500 million incremental facility. The maturity date of the Regency Credit Facility is November 25, 2019.
As of December 31, 2014, Regency had a balance of $1.50 billion outstanding under the Regency Credit Facility in revolving credit loans and approximately $23 million in letters of credit. The total amount available under the Regency Credit Facility, as of December 31, 2014, which is reduced by any letters of credit,2017, the ETP 364-Day Facility had $50 million outstanding, and the amount available for future borrowings was approximately $473$950 million. The weighted average interest rate on the total amount outstanding as of December 31, 20142017 was 2.17%5.00%.
ETLP Credit Facility
The outstanding balance of revolving loans under the RegencyETLP Credit Facility bears interest at LIBOR plus a margin or an alternate base rate. The alternate base rateallowed for borrowings of up to $3.75 billion and was used to calculate interest on base rate loans will be calculated usingprovide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the greater of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.0%. The applicable margin ranges from 0.63% to 1.5% for base rate loans and 1.63% to 2.5% for Eurodollar loans.
Regency pays (i) a commitment fee ranging between 0.3% and 0.45% per annum for the unused portionestablishment of the revolving loan commitments; (ii) a participation fee for each revolving lender participating in letters of credit ranging between 1.63% and 2.5% per annum of the average daily amount of such lender’s letter of credit exposure and; (iii) a fronting fee to the issuing bank of letters of credit equal to 0.2% per annum of the average daily amount of its letter of credit exposure. InETP Credit Facilities on December 2011, Regency amended its credit facility to allow for additional investments in its joint ventures.1, 2017.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintainsETP maintained a $1.50$2.50 billion unsecured revolving credit facilityagreement (the “Sunoco Logistics Credit Facility”) which. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.
In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in November 2018. The Sunoco LogisticsAugust 2019 (the “Bakken Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions.
The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time.Facility”). As of December 31, 2014,2017, the Sunoco LogisticsBakken Credit Facility had $150 million$2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%.
West Texas Gulf Pipe Line Company,PennTex Revolving Credit Facility
PennTex previously maintained a subsidiary$275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.
Sunoco LP Term Loan
Sunoco LP has a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco Logistics, has a $35 million revolving credit facility which expiresLP’s leverage ratio as set forth in April 2015. The facility is availableits previously delivered compliance certificates and the resulting failure to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. Atpay incremental interest owed under the term loan. As of December 31, 2014, this credit facility had $35 million2017, the balance on the term loan was $1.24 billion.
The Sunoco LP term loan was repaid in full and terminated on January 23, 2018. See Sunoco LP Private Offering of outstanding borrowings.Senior Notes above.

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Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. In September 2014,January 2017, Sunoco LP entered into a $1.25 billionlimited waiver to its revolving credit agreement (the “Sunoco LP Credit Facility”),facility, under which matures in September 2019. The Sunoco LP Credit Facility can be increased from time to time uponthe agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s written request, subjectleverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to certain conditions, up to an additional $250 million.pay

incremental interest owed under the revolving credit facility. As of December 31, 2014,2017, the Sunoco LP credit facility had $9 million in standby letters of credit. The amount available for future borrowings on the revolver at December 31, 2017 was $726 million.
On October 16, 2017, Sunoco LP entered into the Fifth Amendment to the Credit Facility had $683 millionAgreement with the lenders party thereto and Bank of outstanding borrowings.America, N.A., in its capacity as a letter of credit issuer, as swing line lender, and as administrative agent. The Fifth Amendment amended the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestitures and the new fuel supply contracts, and (iv) modify the leverage ratio covenant.
Covenants Related to Our Credit Agreements
Covenants Related to the Parent Company
The ETE Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements.
The ETE Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows:
Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company (as defined) to Consolidated EBITDA (as defined in the agreements)therein) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and
Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1.
Covenants Related to ETP
The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The credit agreement relating to the ETP Credit FacilityFacilities contains covenants that limit (subject to certain exceptions) the ETP’sPartnership’s and certain of the ETP’sPartnership’s subsidiaries’ ability to, among other things:
incur indebtedness;
grant liens;
enter into mergers;
dispose of assets;
make certain investments;
make Distributions (as defined in such credit agreement)the ETP Credit Facilities) during certain Defaults (as defined in such credit agreement)the ETP Credit Facilities) and during any Event of Default (as defined in such credit agreement)the ETP Credit Facilities);
engage in business substantially different in nature than the business currently conducted by ETPthe Partnership and its subsidiaries;
engage in transactions with affiliates; and
enter into restrictive agreements.
The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit agreement relatingratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from 0.125% to 0.300%.  The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225%.
The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit FacilityFacilities also containslimit us, on a financial covenant that provides that the Leverage Ratio,rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the ETP Credit Facility, shall not exceedunderlying credit agreements,

of 55.0 to 1, as of the end of each quarter, with a permitted increase which can generally be increased to 5.5 to 1 during a Specified Acquisition Period,Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as definedcalculated in accordance with the ETP Credit Facility.credit agreements.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Covenants RelatedFailure to Regency
The Regency senior notes containcomply with the various restrictive and affirmative covenants that limit, among other things, Regency’sof our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability and the ability of certain of its subsidiaries, to:
to incur additional indebtedness;
debt and/or our ability to pay distributions on, or repurchase or redeem equity interests;

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make certain investments;
incur liens;
enter into certain types of transactions with affiliates; and
sell assets, consolidate or merge with or into other companies.
If the Regency senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, Regency will no longer be subject to these covenants except that the lien covenant will continue to be applicable. ETP has advised Regency that it intends to provide an ETP guarantee with respect to the outstanding Regency senior notes upon the closing of the Regency Merger, and it is expected that this will result in the Regency senior notes being upgraded an investment grade rating by both Moody’s and SAP.
The Regency Credit Facility contains the following financial covenants:
Regency’s consolidated EBITDA ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 5.00 to 1.
Regency’s consolidated EBITDA to consolidated interest expense, as defined in the credit agreement governing the Regency Credit Facility, must be greater than 2.50 to 1.
Regency’s consolidated senior secured leverage ratio for any preceding four fiscal quarter period, as defined in the credit agreement governing the Regency Credit Facility, must not exceed 3.25 to 1.
The Regency Credit Facility also contains various covenants that limit, among other things, the ability of Regency and RGS to:
incur indebtedness;
grant liens;
enter into sale and leaseback transactions;
make certain investments, loans and advances;
dissolve or enter into a merger or consolidation;
enter into asset sales or make acquisitions;
enter into transactions with affiliates;
prepay other indebtedness or amend organizational documents or transaction documents (as defined in the credit agreement governing the Regency Credit Facility);
issue capital stock or create subsidiaries; or
engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Regency Credit Facility or reasonable extensions thereof.distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.
In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from

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borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Sunoco LogisticsBakken Credit Facility
Sunoco Logistics’ $1.50 billion credit facilityThe Bakken Credit Facility contains variousstandard and customary covenants including for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:
prohibition of certain incremental secured indebtedness;
prohibition of certain liens / negative pledge;
limitations on uses of loan proceeds;
limitations on asset sales and purchases;
limitations on permitted business activities;
limitations on mergers and acquisitions;
limitations on investments;
limitations on transactions with affiliates; and
maintenance of commercially reasonable insurance coverage.
A restricted payment covenant is also included in the creationBakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of indebtedness and liens, and other covenants relatednot less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the operation and conductcommercial in-service date of the business of Sunoco LogisticsDakota Access and its subsidiaries. The credit facility also limits Sunoco Logistics, on a rolling four-quarter basis,ETCO Project in order to a maximum total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total consolidated debt, excluding net unamortized fair value adjustments, to consolidated Adjusted EBITDA was 3.7 to 1 at December 31, 2014, as calculated in accordance with the credit agreements.make certain restricted payments thereunder.
The West Texas Gulf Pipeline Company’s $35 million credit facility limits West Texas Gulf, on a rolling four-quarter basis, to a minimum fixed charge coverage ratio of 1.00 to 1. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 1.67 to 1 and 0.85 to 1, respectively, at December 31, 2014.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility requiresFacilities contain various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. The Sunoco LP Credit Facilities  require Sunoco LP to maintain a leverage ratio (as defined therein) of not more than 5.50(a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1. The maximum leverage ratio is1.0, (b) as of March 31, 2018, 6.5 to 1.0, (c) as of June 30, 2018, 6.25 to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (in the case of the quarter ending March 31, 2019 and thereafter, subject to upwards adjustmentincreases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of not more than 6.00 to 1 for a period not to exceed three fiscal quarters in$50 million, as permitted under the event Sunoco LP engages in an acquisition of assets, equity interests, operating lines or divisions by Sunoco LP, a subsidiary, an unrestricted subsidiary or a joint venture for a purchase price of not less than $50 million.Credit Facilities.  Indebtedness under the Sunoco LP Credit FacilityFacilities is secured by a security interest in, among other things, all of the Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Sunoco LP Credit FacilityFacilities will be released.
Compliance With Our Covenants
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions.
We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2014.2017.
7.REDEEMABLEETP CONVERTIBLE PREFERRED UNITS:
ETE Preferred Units
In connection with ETE’s acquisition of Regency’s general partner in 2010, ETE issued 3,000,000 Preferred Units having an aggregate liquidation preference of $300 million. The ETP Convertible Preferred Units were issuedmandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in a private placement at a stated price of $100 per unit and wereour consolidated balance sheets. The ETP Convertible Preferred Units are entitled to a preferential quarterly cash distribution of $2.00 per Preferred Unit.
On April 1, 2013, ETE paid $300 million to redeem (the “Redemption”) all of its 3,000,000 outstanding Preferred Units. Prior to the Redemption, on March 28, 2013, ETE paid the holder of the Preferred Units $40 million in cash in exchange for the holder relinquishing its right to receive any premium in connection with a future redemption or conversion of the Preferred Units.
Prior to the April 1, 2013 Redemption, we recorded non-cash charges of approximately $9 million to increase the carrying value of the Preferred Units to the estimated fair value. During 2012, we recorded non-cash charges of approximately $8 million to increase the carrying value of the Preferred Units to the estimated fair value of $331 million.
Preferred Units of Subsidiary
Holders may elect to convert Regency Preferred Units to Regency Common Units at any time. In July 2013, certain holders of the Regency Preferred Units exercised their right to convert an aggregate 2,459,017 Series A Preferred Units into Regency Common Units. Concurrent with this transaction, a gain of $26 million was recognized in other income, net, related to the

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embedded derivative and reclassified $41 million from the Regency Preferred Units into Regency Common Units. As of December 31, 2014, the remaining Regency Preferred Units were convertible into 2,064,805 Regency Common Units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon. The Regency Preferred Units received fixed quarterly cash distributions of $0.445 per unitETP Preferred Unit if outstanding on the record dates of Regency’sETP’s common unit distributions. Holders can elect to convert RegencyIn January 2017, ETP repurchased all of its 1.9 million outstanding ETP Convertible Preferred Units into Regency Common Units into common units at any timefor cash in accordance with the partnership agreement.aggregate amount of $53 million.
The following table provides a reconciliation of the beginning and ending balances of the Regency Preferred Units:
 
Regency
Preferred
Units
 Amount 
Balance, January 1, 20134.4
 $73
 
Regency Preferred Units converted into Regency Common Units(2.5) (41) 
Balance, December 31, 20131.9
 $32
(1 
) 
Accretion to redemption valueN/A
 1
 
Balance, December 31, 20141.9
 33
 
(1)
This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013 was immaterial.
8.REDEEMABLE NONCONTROLLING INTERESTS:
The noncontrolling interest holders in one of Sunoco Logistics’ consolidated subsidiaries have the option to sell their interests to Sunoco Logistics. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on our consolidated balance sheet.
9.EQUITY:
Limited Partner Units
Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.”
As of December 31, 2014,2017, there were issued and outstanding 538.8 million1.08 billion Common Units representing an aggregate 99.46%94.38% limited partner interest in the Partnership.
Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.

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Common Units
The change in ETE Common Units during the years ended December 31, 20142017, 20132016 and 20122015 was as follows:
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Number of Common Units, beginning of period559.9
 559.9
 445.9
1,046.9
 1,044.8
 1,077.5
Conversion of Class D Units to ETE Common Units—
 —
 0.9
Repurchase of common units under buyback program(21.1) —
 —
—
 —
 (33.6)
Issuance of common units in connection with Southern Union Merger (See Note 3)—
 —
 114.0
Issuance of common units32.2
 2.1
 —
Number of Common Units, end of period538.8
 559.9
 559.9
1,079.1
 1,046.9
 1,044.8
ETE Equity Distribution Agreement
In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the year ended December 31, 2017.
ETE Series A Convertible Preferred Units
 Years Ended December 31,
 2017 2016 2015
Number of Series A Convertible Preferred Units, beginning of period329.3
 —
 —
Issuance of Series A Convertible Preferred Units—
 329.3
 —
Number of Series A Convertible Preferred Units, end of period329.3
 329.3
 —
On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.
The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 2017.
ETE issued 329,295,770 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s

Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.
ETE January 2017 Private Placement and ETP Unit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units for approximately $568 million.
Common Unit Split
On December 23, 2013,July 27, 2015, ETE announced that the board of directors of its general partner approvedcompleted a two-for-one split of the Partnership’s outstanding common units (the “Unit Split”). The Unit Split was completed on January 27, 2014. The Unit Split was effected by a distribution of one ETE Common Unitcommon unit for each common unit outstanding and held by unitholders of record at the close of business on January 13, 2014.July 15, 2015.
Repurchase Program
In December 2013,February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $1an additional $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 21.133.6 million ETE Common Units under this program through May 23, 2014,in 2015. No units were repurchased under this program in 2017 or 2016, and there was $936 million available to use under the program was completed.
In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $2 billionas of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements.December 31, 2017.
Class D Units
On May 1,In 2013, Jamie Welch was appointed Group Chief Financial Officer and Head of Corporate Development of LE GP, LLC, the general partner of ETE, effective June 24, 2013. Pursuant to an equity award agreement between Mr. Welch and the Partnership dated April 23, 2013, Mr. Welch received 1,500,000 restricted ETE common units representing limited partner interest. The restricted ETE common units were subject to vesting, based on continued employment with ETE. On December 23, 2013, ETE and Mr. Welch entered into (i) a rescission agreement in order to rescind the original offer letter to the extent it relates to the award of 1,500,000 common units of ETE to Mr. Welch, the original award agreements, and the receipt of cash amounts by Mr. Welch with respect to such awarded units and (ii) a new Class D Unit Agreement between ETE and Mr. Welch providing for the issuance to Mr. Welch of an aggregate of 1,540,000issued 3,080,000 Class D Units of ETE which number ofpursuant to an agreement with a former executive. The Class D Units includes an additional 40,000 Class D Units that were issued to Mr. Welch in connection with other changes to his original offer letter.
Under the terms of the Class D Unit Agreement, 30% of the Class D Units will convertconvertible to ETE common units on a one-for-one basis on March 31, 2015, and the remaining 70% will convertCommon Units, subject to ETE common units on a one-for-one basis on March 31, 2018, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocatedcertain vesting requirements which were not met prior to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date.former executive’s termination in 2016.
Sale of Common Units by Subsidiaries
The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented.

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Sale of Common Units by ETP
The following table summarizes ETP’s public offerings of ETP Common Units, all of which have been registered under the Securities Act of 1933 (as amended):
Date 
Number of
ETP Common
Units
 
Price per ETP
Unit
 Net Proceeds
July 2012 15.5
 $44.57
 $671
April 2013 13.8
 48.05
 657
Proceeds from the offerings listed above were used to repay amounts outstanding under the ETP Credit Facility and/or to fund capital expenditures and capital contributions to joint ventures, and for general partnership purposes.
ETP’s Equity Distribution Program
From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.
In January 2013 andconnection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2013,2017, ETP entered into an equity distribution agreements pursuant to which ETP may sell from time to time ETP Common Units havingagreement with an aggregate offering prices ofprice up to $200 million and $800 million, respectively. $1.00 billion.

During the year ended December 31, 2014,2017, ETP issued approximately 2.722.6 million units for $144$503 million, net of commissions of $2 million. No amounts of ETP Common Units remain available to be issued under the January 2013 and May 2013 equity distribution agreements.
In May 2014 and November 2014, ETP entered into equity distribution agreements pursuant to which ETP may sell from time to time ETP Common Units having aggregate offering prices of up to $1.0 billion and $1.50 billion, respectively. During the year ended December 31, 2014, ETP issued approximately 18.8 million units for $1.08 billion, net of commissions of $11$5 million. As of December 31, 2014, approximately $1.41 billion2017, $752 million of ETPETP’s Common Units remained available to be issued under ETP’s currently effective equity distribution agreements.agreement.
ETP’s Equity Incentive Plan Activity
As discussed in Note 10, ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations.
ETP’s Distribution Reinvestment Program
ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan.
During the years ended December 31, 2014, 20132017, 2016 and 2012,2015, aggregate distributions of approximately $155$228 million, $109$216 million, and $43$360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of approximately 6.125.5 million ETP Common Units.
As of December 31, 2014,2017, a total of 7.320.8 million ETP Common Units remain available to be issued under the existing registration statement.
August 2017 Units Offering
In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.
ETP Class E Units
TheseThere are currently 8.9 million ETP Class E Units outstanding, all of which are currently owned by HHI. The ETP Class E Units generally do not have any voting rights. The ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the ETP Class E Unitholders, up to $1.41$1.41 per unit per year, with any excess thereof available for distribution to ETP Unitholders other thanyear. As the holders of ETP Class E Units in proportion to their respective interests. The ETP Class E Units are treated by ETP as treasury units for accounting purposes because they are owned by a wholly-owned subsidiary, of ETP Holdco, Heritage Holdings, Inc.the cash distributions on those units are eliminated in ETP’s consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire some or all of the ETP Class E Units at a future date. All of the 8.9 million ETP Class E Units outstanding are held by a subsidiary of ETP and therefore are reflected by ETP as treasury units in its consolidated financial statements.

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ETP Class G Units
In conjunction with the Sunoco Merger, ETP amended its partnership agreement to create ETP Class F Units. The number of ETP Class F Units issued was determined at the closing of the Sunoco Merger and equaledThere are currently 90.7 million, which included 40 million ETP Class FG Units issued in exchange for cash contributedoutstanding, all of which are held by Sunoco, Inc. to ETP immediately prior to or concurrent with the closingwholly-owned subsidiaries of the Sunoco Merger.ETP. The ETP Class FG Units generally diddo not have any voting rights. The ETP Class FG Units wereare entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and its subsidiaries, (otherother than ETP Holdco)Holdco, and available for distribution, up to a maximum of $3.75 per ETP Class FG Unit per year. In April 2013, all of the outstanding ETP Class F Units were exchanged for ETP Class G Units on a one-for-one basis. The ETP Class G Units have terms that are substantially the same as the ETP Class F Units, with the principal difference between the ETP Class G Units and the ETP Class F Units being that allocationsAllocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. The ETP Class G UnitsThese units are held by a subsidiary of ETP and therefore are reflected by ETP as treasury units in itsthe consolidated financial statements.
ETP Class H Units and Class I Units
Currently Outstanding
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which arewere generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05%90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 50.05%90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters.
Pending Transaction
In December 2014, The Class H units were cancelled in connection with the merger of ETP and ETE announced the final terms of a transaction, whereby ETE will transfer 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP will also issue 100 in April 2017.

ETP Class I Units as described below. In addition, ETE and ETP agreed to reduce the IDR subsidies that ETE previously agreed to provide to ETP, with such reductions occurring in 2015 and 2016.
In connection with the transaction,Bakken Pipeline Transaction discussed in Note 3, in March 2015, ETP will also issueissued 100 ETP Class I Units. The ETP Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the ETP Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the ETP Class I Units and (ii) after making cash distributions to ETP Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the ETP Class I Units in an amount equal to the excess of the distribution amount set forth in the ETPETP’s Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter endingended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “ETP Quarterly“Quarterly Distributions of Available Cash” inCash.” Subsequent to the column titled “Pro Forma forApril 2017 merger of ETP Class H and Sunoco Logistics, 100 Class I Units.”Units remain outstanding.
Bakken Equity Sale of Common Units by Regency
The following table summarizes Regency’s public offerings of Regency Common Units during the periods presented:
Date 
Number of
Regency Common
Units
 
Price per 
Regency Unit
 Net Proceeds
March 2012 12.7
 $24.47
 $297

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Proceeds were used to repay amounts outstanding under the Regency Credit Facility and/or fund capital expenditures and capital contributions to joint ventures, as well as for general partnership purposes.
Regency issued 4.0 million, 140.4 million and 8.2 million Regency Common UnitsIn February 2017, Bakken Holdings Company LLC, an entity in connection with the Hoover, PVR and Eagle Rock Midstream acquisitions, respectively.
In June 2014, Regencywhich ETP indirectly owns a 100% membership interest, sold 14.4 million Regency Common Units to a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of ETEDakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
Class K Units
On December 29, 2016, ETP issued to certain of its indirect subsidiaries, in exchange for approximately $400 million. Proceeds from the issuance were used to pay down borrowings on the Regency Credit Facility, to redeem certain Regency senior notes and for general partnership purposes. In July 2014, Regency sold an additional 16.5 million Regency Common Units to a wholly-owned subsidiary of ETE in connection with the Eagle Rock Midstream Acquisition for approximately $400 million. Proceeds from the issuance were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition.
Regency’s Equity Distribution Program
From time to time, Regency has sold Regency Common Units through an equity distribution agreement. Such sales of Regency Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between uscontributions and the sales agent which is the counterparty to the equity distribution agreement.
In June 2012, Regency entered into an equity distribution agreement with Citigroup Global Markets Inc. under which Regency may offer and sell Regency Common Units,exchange of outstanding common units representing limited partner interests having an aggregate offering pricein ETP, Class K Units, each of upwhich is entitled to $200 milliona quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from timeETP Holdco. If ETP is unable to time through Citi, as sales agent for Regency. Forpay the years endedClass K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2014 and 2013, Regency received net proceeds2017, a total of $34101.5 million and $149 million, respectively, from Regency CommonClass K Units issued pursuant to this equity distribution agreement. No amounts remain available to be issued under this agreement and it is no longer effective.were held by wholly-owned subsidiaries of ETP.
In May 2014, Regency entered into an equity distribution agreement with a group of banks and investment companies under which Regency may offer and sell Regency Common Units, representing limited partner interests, for an aggregate offering price of up to $400 million, from time to time through this group of institutions, as sales agent for Regency. For the year ended December 31, 2014, Regency received net proceeds of $395 million from Regency Common Units issued pursuant to this equity distribution agreement. No amounts remained available to be issued under this agreement and it is no longer effective.
In January 2015, Regency entered into an equity distribution agreement with a group of banks and investment companies (the “Managers”) under which Regency may offer and sell Regency Common Units for an aggregate offering price of up to $1 billion, from time to time through the Managers, as sales agent for Regency. Regency intends to use the net proceeds from the sale of Regency Common Units for general partnership purposes.
Sales of Common Units by Sunoco Logistics
Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.
In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. DuringIn connection with the year ended December 31, 2014, Sunoco Logistics received proceeds of $477 million, net of commissions of $5 million, fromMerger, the issuance of 10.3 million common units pursuant to theprevious Sunoco Logistics equity distribution agreement which were used for general partnership purposes.was terminated.
ETP Series A and Series Preferred Units
In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit.
Additionally, Sunoco Logistics completedDistributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an overnight public offeringannual floating rate of 7.7 millionthe three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15,

2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for net proceeds$20.00 per common unit in cash. ETP now owns all of $362 million in September 2014. The net proceeds from this offering were used to repay outstanding borrowings under the $1.50 billion Sunoco Logistics Credit Facilityeconomic interests of PennTex, and for general partnership purposes.PennTex common units are no longer publicly traded or listed on the NASDAQ.
Sales of Common Units by Sunoco LP
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.
In October 2014 and November 2014,2016, Sunoco LP entered into an equity distribution agreement pursuant to which Sunoco LP may sell from time to time common units having aggregate offering prices of up to $400 million. Through December 31, 2016, Sunoco LP received net proceeds of $71 million from the issuance of 2.8 million Sunoco LP common units pursuant to such equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. From January 1, 2017 through December 31, 2017, Sunoco LP issued an aggregateadditional 1.3 million units with total net proceeds of 9.1$33 million, net of commissions of $0.3 million. As of December 31, 2017, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP.
On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership.
In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha Petroleum, Ltd as consideration for the contribution by Aloha to an underwritten public offering. Aggregateindirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries.
In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $405 million$213 million. The net proceeds from the offering were used to repay amounts outstanding balances under the $1.25 billion Sunoco LP Credit Facilityrevolving credit facility.
Sunoco LP Series A Preferred Units
On March 30, 2017, the Partnership purchased 12.0 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units is10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference.
In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and for general partnership purposes.a 1% call premium plus accrued and unpaid quarterly distributions.
Contributions to Subsidiaries
The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain

its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest.

F - 51

The Parent Company owns the entire general partner interest in Regency through its ownership of Regency GP. Regency GP has the right, but not the obligation, to contribute a proportionate amount of capital to Regency to maintain its current general partner interest. Regency GP’s interest in Regency’s distributions is reduced if Regency issues additional units and Regency GP does not contribute a proportionate amount of capital to Regency to maintain its General Partner interest.
Parent Company Quarterly Distributions of Available Cash
Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and RegencySunoco LP related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG.
Our distributions declared duringand paid with respect to our common units for the years ended December 31, 2014, 2013 and 2012periods presented were as follows:
 
Quarter Ended          Record Date Payment Date  Rate
December 31, 2011  February 7, 2012 February 17, 2012  $0.3125
March 31, 2012 May 4, 2012 May 18, 2012  0.3125
June 30, 2012 August 6, 2012 August 17, 2012  0.3125
September 30, 2012 November 6, 2012 November 16, 2012  0.3125
December 31, 2012 February 7, 2013 February 19, 2013  0.3175
March 31, 2013 May 6, 2013 May 17, 2013  0.3225
June 30, 2013 August 5, 2013 August 19, 2013  0.3275
September 30, 2013 November 4, 2013 November 19, 2013  0.3363
December 31, 2013 February 7, 2014 February 19, 2014  0.3463
March 31, 2014 May 5, 2014 May 19, 2014  0.3588
June 30, 2014 August 4, 2014 August 19, 2014  0.3800
September 30, 2014 November 3, 2014 November 19, 2014  0.4150
December 31, 2014 February 6, 2015 February 19, 2015 0.4500
ETP’s Quarterly Distributions of Available Cash
ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its General Partner in its sole discretion to provide for the proper conduct of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in ETP’s Partnership Agreement.

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ETP’s distributions declared during the periods presented below were as follows:
Quarter Ended  Record Date Payment Date  
Distribution per
ETP Common Unit
December 31, 2011  February 7, 2012 February 14, 2012 $0.8938
March 31, 2012 May 4, 2012 May 15, 2012 0.8938
June 30, 2012 August 6, 2012 August 14, 2012 0.8938
September 30, 2012 November 6, 2012 November 14, 2012 0.8938
December 31, 2012 February 7, 2013 February 14, 2013 0.8938
March 31, 2013 May 6, 2013 May 15, 2013 0.8938
June 30, 2013 August 5, 2013 August 14, 2013 0.8938
September 30, 2013 November 4, 2013 November 14, 2013 0.9050
December 31, 2013 February 7, 2014 February 14, 2014 0.9200
March 31, 2014 May 5, 2014 May 15, 2014 0.9350
June 30, 2014 August 4, 2014 August 14, 2014 0.9550
September 30, 2014 November 3, 2014 November 14, 2014 0.9750
December 31, 2014 February 6, 2015 February 13, 2015 0.9950
In connection with transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods based on (i) the currently effective partnership agreement provisions, (ii) the assumed closing of the issuance of additional ETP Class H Units and ETP Class I Units, which is expected to occur in March 2015, and (iii) the assumed closing of the Regency Merger, which is expected to occur in the second quarter of 2015:
Years Ending December 31, Currently Effective 
Pro Forma for
ETP Class H and
Class I Units(1)
 
Pro Forma for Regency Merger(2)
2015 $86
 $31
 $91
2016 107
 77
 142
2017 85
 85
 145
2018 80
 80
 140
2019 70
 70
 130
2020 35
 35
 50
2021 35
 35
 35
2022 35
 35
 35
2023 35
 35
 35
2024 18
 18
 18
Quarter Ended        Record DatePayment DateRate
December 31, 2014February 6, 2015February 19, 20150.2250
March 31, 2015May 8, 2015May 19, 20150.2450
June 30, 2015August 6, 2015August 19, 20150.2650
September 30, 2015November 5, 2015November 19, 20150.2850
December 31, 2015February 4, 2016February 19, 20160.2850
March 31, 2016 (1)
May 6, 2016May 19, 20160.2850
June 30, 2016 (1)
August 8, 2016August 19, 20160.2850
September 30, 2016 (1)
November 7, 2016November 18, 20160.2850
December 31, 2016 (1)
February 7, 2017February 21, 20170.2850
March 31, 2017 (1)
May 10, 2017May 19, 20170.2850
June 30, 2017 (1)
August 7, 2017August 21, 20170.2850
September 30, 2017 (1)
November 7, 2017November 20, 20170.2950
December 31, 2017 (1)
February 8, 2018February 20, 20180.3050
(1) 
Pro forma amounts reflectCertain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the IDR subsidies, as adjusteddistribution for the pending issuancequarter ended March 31, 2016 and, in lieu of additional ETP Class H Units and ETP Class I Units discussed above, as well asreceiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the ETP Class I Units. The issuanceparticipating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See additional ETP Class H Units and ETP Class I Units is expected to close in March 2015.
(2)
Pro forma amounts reflect the IDR subsidies, as adjusted for (i) the pending issuance of additional ETP Class H Units and ETP Class I Units (as described in Note (1) above) and (ii) the pending Regency Merger. Amounts reflected above assume that the Regency Merger is closed subsequent to the record date for the first quarter of 2015 distribution payment and prior to the record date for the second quarter 2015 distribution payment.information below.
The amounts reflected above includeOur distributions declared and paid with respect to our Convertible Unit during the relinquishment of $350 million in the aggregate of incentive distributions that would potentially be made to ETE over the first forty fiscal quarters commencing immediately after the consummation of the Susser Merger. Such relinquishments would cease upon the agreement of an exchange of the Sunoco LP general partner interestyears ended December 31, 2016 and the incentive distribution rights between ETE and ETP.2017 were as follows:

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Quarter Ended          Record Date Payment Date  Rate
March 31, 2016 May 6, 2016 May 19, 2016 $0.1100
June 30, 2016 August 8, 2016 August 19, 2016 0.1100
September 30, 2016 November 7, 2016 November 18, 2016 0.1100
December 31, 2016 February 7, 2017 February 21, 2017 0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100
December 31, 2017 February 8, 2018 February 20, 2018 0.1100
Table of Contents

Regency’sETP’s Quarterly Distributions of Available Cash
Regency’s Partnership Agreement requires that Regency distribute all of its Available Cash to its Unitholders and its General PartnerUnder ETP’s limited partnership agreement, within 45 days after the end of each quarter, to unitholders of record on the applicable record date, as determined by the general partner. The term Available Cash generally consists ofETP distributes all cash and cash equivalents on hand at the end of thatthe quarter, less the amount of cash reserves established by the general partner to: (i) provide for the properin its discretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds forETP’s business. ETP will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

If cash distributions exceed $0.0833 per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”
As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount IDRs 
Partners (1)
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%
(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:
Quarter Ended ETP Sunoco Logistics
December 31, 2014 $0.6633
 $0.4000
March 31, 2015 0.6767
 0.4190
June 30, 2015 0.6900
 0.4380
September 30, 2015 0.7033
 0.4580
December 31, 2015 0.7033
 0.4790
March 31, 2016 0.7033
 0.4890
June 30, 2016 0.7033
 0.5000
September 30, 2016 0.7033
 0.5100
December 31, 2016 0.7033
 0.5200
Distributions on common units declared and paid by Post-Merger ETP were as follows:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 16, 2017 $0.5350
June 30, 2017 August 7, 2017 August 15, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
December 31, 2017 February 8, 2018 February 14, 2018 0.5650

In connection with previous transactions, we have agreed to relinquish its right to the General Partner for any one or morefollowing amounts of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.incentive distributions in future periods:
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Distributions declared and paid by Regency duringETP to the years ended December 31, 2014, 2013Series A and 2012Series B preferred unitholders were as follows:
Quarter Ended  Record Date  Payment Date  
Distribution per
Regency Common
Unit
December 31, 2011 February 6, 2012 February 13, 2012 $0.4600
March 31, 2012 May 7, 2012  May 14, 2012 0.4600
June 30, 2012 August 6, 2012 August 14, 2012 0.4600
September 30, 2012 November 6, 2012 November 14, 2012 0.4600
December 31, 2012 February 7, 2013 February 14, 2013 0.4600
March 31, 2013 May 6, 2013 May 13, 2013 0.4600
June 30, 2013 August 5, 2013 August 14, 2013 0.4650
September 30, 2013 November 4, 2013 November 14, 2013 0.4700
December 31, 2013 February 7, 2014 February 14, 2014 0.4750
March 31, 2014 May 8, 2014 May 15, 2014 0.4800
June 30, 2014 August 7, 2014 August 14, 2014 0.4900
September 30, 2014 November 4, 2014 November 14, 2014 0.5025
December 31, 2014 February 6, 2015 February 13, 2015 0.5025
 Distribution per Preferred Unit
Quarter Ended Record Date Payment Date Series A Series B
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
 $16.378
In conjunction with Southern Union’s contributions of SUGS to Regency, ETE agreed to relinquish incentive distributions on the 31.4 million Regency Common Units issued for twenty-four months subsequent to the transaction closing.
Sunoco Logistics Quarterly Distributions of Available Cash
Distributions declared by Sunoco Logistics during the years ended December 31, 2014, 2013 and 2012 were as follows:
Quarter Ended  Record Date  Payment Date  
Distribution per
Sunoco Logistics
Common Unit
December 31, 2012 February 8, 2013 February 14, 2013 $0.2725
March 31, 2013 May 9, 2013 May 15, 2013 0.2863
June 30, 2013 August 8, 2013 August 14, 2013 0.3000
September 30, 2013 November 8, 2013 November 14, 2013 0.3150
December 31, 2013 February 10, 2014 February 14, 2014 0.3312
March 31, 2014 May 9, 2014 May 15, 2014 0.3475
June 30, 2014 August 8, 2014 August 14, 2014 0.3650
September 30, 2014 November 7, 2014 November 14, 2014 0.3825
December 31, 2014 February 9, 2015 February 13, 2015 0.4000
Sunoco Logistics Unit Split
On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis.

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Sunoco LP Quarterly Distributions of Available Cash
The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Effective July 1, 2015, ETE exchanged 21 million ETP common units, owned by ETE, the owner of ETP’s general partner interest, for 100% of the general partner interest and all of the IDRs of Sunoco LP. ETP had previously owned our IDRs since September 2014, prior to that date the IDRs were owned by Susser.
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs
Minimum Quarterly Distribution $0.4375 100% —%
First Target Distribution $0.4375 to $0.503125 100% —%
Second Target Distribution $0.503125 to $0.546875 85% 15%
Third Target Distribution $0.546875 to $0.656250 75% 25%
Thereafter Above $0.656250 50% 50%

Distributions declared and paid by Sunoco LP subsequent to our acquisition on August 29, 2014for the periods presented were as follows:
Quarter Ended Record Date Payment Date 
Distribution per
Sunoco LP
Common Unit
September 30, 2014 November 18, 2014 November 28, 2014 $0.5457
December 31, 2014 February 17, 2015 February 27, 2015 0.6000
Quarter EndedRecord DatePayment DateRate
December 31, 2014February 17, 2015February 27, 20150.6000
March 31, 2015May 19, 2015May 29, 20150.6450
June 30, 2015August 18, 2015August 28, 20150.6934
September 30, 2015November 17, 2015November 27, 20150.7454
December 31, 2015February 5, 2016February 16, 20160.8013
March 31, 2016May 6, 2016May 16, 20160.8173
June 30, 2016August 5, 2016August 15, 20160.8255
September 30, 2016November 7, 2016November 15, 20160.8255
December 31, 2016February 13, 2017February 21, 20170.8255
March 31, 2017May 9, 2017May 16, 20170.8255
June 30, 2017August 7, 2017August 15, 20170.8255
September 30, 2017November 7, 2017November 14, 20170.8255
December 31, 2017February 06, 2018February 14, 20180.8255
Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
December 31,December 31,
2014 20132017 2016
Available-for-sale securities$3
 $2
$8
 $2
Foreign currency translation adjustment(3) (1)(5) (5)
Net losses on commodity related hedges(1) (4)
Actuarial gain (loss) related to pensions and other postretirement benefits(57) 56
(5) 7
Investments in unconsolidated affiliates, net2
 8
5
 4
Subtotal(56) 61
3
 8
Amounts attributable to noncontrolling interest51
 (52)(3) (8)
Total AOCI included in partners’ capital, net of tax$(5) $9
$—
 $—
The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss):
December 31,December 31,
2014 20132017 2016
Available-for-sale securities$(1) $(1)$(2) $(2)
Foreign currency translation adjustment2
 1
3
 3
Actuarial gain relating to pension and other postretirement benefits(37) (39)
Actuarial loss relating to pension and other postretirement benefits3
 —
Total$(36) $(39)$4
 $1
10.9.UNIT-BASED COMPENSATION PLANS:
We, ETP and Sunoco Logistics and RegencyLP have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards.
ETE Long-Term Incentive Plan
The Board of Directors or the Compensation Committee of the board of directors of the our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom

units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 6,000,00012.0 million units. As of December 31, 2014, 5,690,1012017, 10.8 million units remain available to be awarded under the plan.
InDuring the year ended December 2013, 1,540,000 Class D Units were granted to an31, 2017, 1.2 million ETE employee, Jamie Welch. Under the terms of the Class D Unit Agreement, 30% of the Class D Units granted to Welch will convert to ETE common units on a one-for-one basis on March 31, 2015, and the remaining 70% will convert to ETE common units on a one-for-one basis on March 31, 2018, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocated to the Class D Units

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being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date. See further discussion at Note 9 to our consolidated financial statements.
During 2014, no awards were granted to ETE employees and 3,687certain employees of ETP and 15,648 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest 60% in three years and 40% in five years and do not entitle the holders to receive distributions during the vesting period.
During 2014,the year ended December 31, 2017 and 2016, a total of 30,0342,018 and 28,648 ETE Common Units vested, with a total fair value of $1.5 million$39 thousand and $205 thousand, respectively, as of the vesting date. As of December 31, 2014, excluding Class D units,2017, a total of 34,3401,251,002 restricted units granted to ETE employees and directors remain outstanding, for which we expect to recognize a total of less than $1$21 million in compensation over a weighted average period of 2.13.5 years. As of December 31, 2014, a total of 1,540,000 Class D Units granted to Mr. Welch remain outstanding, for which we expect to recognize a total of $23 million in compensation over a weighted average period of 3.0 years.
ETPSubsidiary Unit-Based Compensation Plans
Restricted Units
Each of ETP and Sunoco LP has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards” to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a specified timefive-year period, typically a five-year serviceand vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awardsThe Subsidiary Unit Awards entitle the recipientsgrantees of the unit awards to receive with respect to each ETP Common Unit subject to such award that has not either vested or been forfeited, aan amount of cash payment equal to eachthe per unit cash distribution per ETP Common Unitdistributions made by ETP on its Common Units promptly following each such distribution by ETP to its Unitholders. We refer to these rights as “distribution equivalent rights.” Under ETP’s equity incentive plans, ETP’s non-employee directors each receive grants with a five-year service vesting requirement.the respective subsidiaries during the period the restricted unit is outstanding.
The following table showssummarizes the activity of the ETP awards granted to employees and non-employee directors:Subsidiary Unit Awards:
Number of
ETP Units
 
Weighted Average
Grant-Date Fair Value
Per ETP Unit
ETP Sunoco LP
Unvested awards as of December 31, 20133.2
 $49.65
Number of
Units
 
Weighted  Average
Grant-Date Fair Value
Per Unit
 
Number of
Units
 
Weighted  Average
Grant-Date Fair Value
Per Unit
Unvested awards as of December 31, 20169.4
 $27.68
 2.0
 $34.43
Legacy Sunoco Logistics unvested awards as of December 31, 20163.2
 28.57
 —
 —
Awards granted1.0
 60.85
4.9
 17.69
 0.2
 28.31
Awards vested(0.5) 48.12
(2.3) 34.22
 (0.3) 45.48
Awards forfeited(0.1) 32.36
(1.1) 25.03
 (0.2) 34.71
Unvested awards as of December 31, 20143.6
 53.83
Unvested awards as of December 31, 201714.1
 23.18
 1.7
 31.89
During the years ended December 31, 2014, 2013 and 2012, the weighted average grant-date fair value per unit award granted was $60.85, $50.54 and $43.93, respectively.
Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31:       
2017  $17.69
   $28.31
2016  23.82
   26.95
2015  23.47
   40.63
The total fair value of awardsSubsidiary Unit Awards vested for the years ended December 31, 2017, 2016, and 2015 was $26$40 million, $29$40 million, and $29$57 million, respectively, based on the market price of ETP Common Unitsthe respective subsidiaries’ common units as of the vesting date. As of December 31, 2014, a total of 3.62017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $216 million, unit awards remain unvested, for which ETP expects to recognize a total of $128 million in compensation expense over aand the weighted average period of 2.0 years.
Cash Restricted Units
ETP has also granted cash restricted units,over which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipientthis cost is expected to receive cash equal to the market value of one ETP Common Unit upon vesting. As of December 31, 2014, a total of 0.4 million unvested cash restricted units units were outstanding.
Based on the trading price of ETP Common Units at December 31, 2014, ETP expects to recognize $24 million of unit-based compensationbe recognized in expense related to non-vested cash restricted units over a period of 1.8is 2.8 years.
Sunoco Logistics Unit-Based Compensation Plan
Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco Logistics covering an additional 0.7 million Sunoco, Inc. common units. As of December 31, 2014, a total of 1.5 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $33 million of expense over a weighted-average period of 2.9 years.

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Regency Unit-Based Compensation Plans
Regency has the following awards outstanding as of December 31, 2014:
107,650 Regency Common Unit options, all of which are exercisable, with a weighted average exercise price of $22.68 per unit option; and
2,167,719 Regency Phantom Units, with a weighted average grant date fair value of $24.31 per Phantom Unit.
Regency expects to recognize $42 million of compensation expense related to the Regency Phantom Units over a period of 3.9 years.
Cash Restricted Units
Regency began granting cash restricted units in 2014. These awards are service condition (time-based) grants which vest 100% at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one Regency Common Unit upon vesting. Regency has 379,328 cash restricted units outstanding at December 31, 2014.
Based on the trading price of Regency Common Units at December 31, 2014, Regency expects to recognize $7 million of unit-based compensation expense related to non-vested cash restricted units over a period of 2.5 years.
11.10.INCOME TAXES:
As a partnership, we are not subject to U.S.United States federal income tax and most state income taxes. However, the partnershipPartnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Current expense (benefit):          
Federal$321
 $51
 $(3)$54
 $(47) $(308)
State86
 (1) 6
(16) (34) (54)
Total407
 50
 3
38
 (81) (362)
Deferred expense (benefit):          
Federal(53) (14) 41
(2,055) (189) 268
State3
 57
 10
184
 12
 (29)
Total(50) 43
 51
(1,871) (177) 239
Total income tax expense from continuing operations$357
 $93
 $54
Total income tax expense (benefit) from continuing operations$(1,833) $(258) $(123)

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Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to U.S.United States federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and the Susser Merger (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S.United States statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 20142017, 2016 and 20132015 is as follows:
 December 31, 2014 December 31, 2013
 
Corporate Subsidiaries(1)
 
Partnership(2)
 Consolidated 
Corporate Subsidiaries(1)
 
Partnership(2)
 Consolidated
Income tax expense (benefit) at U.S. statutory rate of 35 percent$212
 $—
 $212
 $(172) $—
 $(172)
Increase (reduction) in income taxes resulting from:    
      
Nondeductible goodwill—
 —
 —
 241
 —
 241
Nondeductible goodwill included in the Lake Charles LNG Transaction105
 —
 105
 —
 —
 —
Premium on debt retirement(10) —
 (10) —
 —
 —
Foreign taxes(8) —
 (8) —
 —
 —
State income taxes (net of federal income tax effects)9
 46
 55
 31
 10
 41
Other3
 —
 3
 (16) (1) (17)
Income tax from continuing operations$311
 $46
 $357
 $84
 $9
 $93
 2017 2016 2015
Income tax expense (benefit) at United States statutory rate of 35 percent$248
 $71
 $316
Increase (reduction) in income taxes resulting from:     
Partnership earnings not subject to tax(477) (576) (355)
Goodwill impairment207
 278
 —
State tax, net of federal tax benefit124
 (10) (29)
Dividend received deduction(14) (15) (22)
Federal rate change(1,812) —
 —
Audit settlement—
 —
 (7)
Change in tax status of subsidiary(124) —
 —
Other15
 (6) (26)
Income tax expense (benefit) from continuing operations$(1,833) $(258) $(123)
(1)

Includes ETP Holdco, Susser, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd, Pueblo, Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. ETP Holdco, which was formed via the Sunoco Merger and the ETP Holdco Transaction (see Note 3), includes Sunoco, Inc. and Panhandle. ETE held a 60% interest in ETP Holdco until April 30, 2013. Subsequent to the ETP Holdco Acquisition (see Note 3) on April 30, 2013, ETP owns 100% of ETP Holdco.
(2)
Includes ETE and its respective subsidiaries that are classified as pass-through entities for federal income tax purposes.

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Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
December 31,December 31,
2014 20132017 2016
Deferred income tax assets:      
Net operating losses and alternative minimum tax credit$116
 $217
$683
 $472
Pension and other postretirement benefits47
 57
21
 30
Long term debt53
 108
Long-term debt14
 32
Other111
 104
191
 182
Total deferred income tax assets327
 486
909
 716
Valuation allowance(84) (74)(189) (118)
Net deferred income tax assets243
 412
720
 598
      
Deferred income tax liabilities:      
Properties, plants and equipment(1,583) (1,624)
Inventory(153) (302)
Property, plant and equipment(1,036) (1,633)
Investments in unconsolidated affiliates(2,530) (2,245)(2,726) (3,789)
Trademarks(355) (180)(173) (273)
Other(32) (45)(100) (15)
Total deferred income tax liabilities(4,653) (4,396)(4,035) (5,710)
Net deferred income tax liability(4,410) (3,984)
Less: current portion of deferred income tax liabilities, net(85) (119)
Accumulated deferred income taxes$(4,325) $(3,865)
Net deferred income taxes$(3,315) $(5,112)
The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:
December 31,December 31,
2014 20132017 2016
Net deferred income tax liability, beginning of year$(3,984) $(3,696)$(5,112) $(4,590)
Susser acquisition(488) —
SUGS Contribution to Regency—
 (115)
Tax provision (including discontinued operations)62
 (124)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)—
 (460)
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3)—
 (243)
Tax provision, including provision from discontinued operations1,825
 201
Other—
 (49)(28) (20)
Net deferred income tax liability$(4,410) $(3,984)$(3,315) $(5,112)
ETP Holdco Susser and certain other corporate subsidiaries have gross federal net operating loss carryforwardscarryforward tax benefits of $5$403 million, all of which will expire in 2032 and 2033.2031 through 2037. Our corporate subsidiaries had less than $1have $62 million of federal alternative minimum tax credits at December 31, 2014.2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have state net operating loss carryforward benefits of $111$274 million, $217 million net of federal tax, which expire between 2014January 1, 2018 and 2033. The2037. A valuation allowance of $84$186 million is applicable to the state net operating loss carryforward benefits applicable to Sunoco, Inc. pre-acquisition periods.

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Tablesignificant restriction on their use in the Commonwealth of ContentsPennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.


The following table sets forth the changes in unrecognized tax benefits:
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Balance at beginning of year$429
 $27
 $2
$615
 $610
 $440
Additions attributable to acquisitions—
 —
 28
Additions attributable to tax positions taken in the current year20
 —
 —
—
 8
 178
Additions attributable to tax positions taken in prior years(1) 406
 —
28
 18
 —
Settlements(5) —
 —
Reduction attributable to tax positions taken in prior years(25) (20) —
Lapse of statute(3) (4) (3)(9) (1) (8)
Balance at end of year$440
 $429
 $27
$609
 $615
 $610
As of December 31, 2014,2017, we have $439$605 million ($425576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it
Our policy is reasonably possible that its unrecognizedto accrue interest expense and penalties on income tax benefits may be reduced by $4 million ($2underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $9 million, net of federal tax) within the next twelve months due to settlement of certain positions.tax.
Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 open statute years, Sunoco, Inc. has proposed tofiled amended returns with the IRS thatexcluding these government incentive payments be excluded from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful within its claims,litigation, it will receive tax refunds of approximately $372$530 million. However, due to the uncertainty surrounding the claims,litigation, a reserve of $372$530 million was established for the full amount of the claims.litigation. Due to the timing of the expected settlement of the claimslitigation and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2014.2017.
Our policy isIn December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety.  In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to accrue interest expensethe uniformity clause violation; however, the Court reversed with respect to the remedy and penalties oninstead severed the flat-dollar limitation, leaving the percentage-based limitation intact.  Nextel has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court.  Sunoco, Inc. has recognized approximately $67 million ($53 million after federal income tax underpayments (overpayments)benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as a componentrelates to its cases currently held pending the Nextel matter.  However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 million after federal income tax expense. During 2014, we recognized interest and penalties of less than $1 million. At December 31, 2014, we have interest and penalties accrued of $6 million, net of tax.benefits) against the receivable.
In general, ETEETP and its subsidiaries are no longer subject to examination by the IRSInternal Revenue Service (“IRS”), and most state jurisdictions, for 20102013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007, and Southern Union and its subsidiaries are no longer subject to examination by the IRS for tax years prior to and 2004. Regency and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.
Sunoco, Inc. has been examined by the IRS for tax years through 2012.2013. However, the statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statue,statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments. Southern Union is under examination for the tax years 2004 through 2009. As of December 31, 2014, the IRS has proposed only one adjustment for the years under examination. For the 2006 tax year, the IRS is challenging $545 million of the $690 million of deferred gain associated with a like kind exchange involving certain assets of its distribution operations and its gathering and processing operations. We have vigorously defended this tax position and believe we have reached a tentative settlement with the IRS which will not have a material impact on our consolidated financial position or results of operations. Regency is also under examination by the IRS for the 2007 and 2008 tax years. The IRS has proposed adjustments in both of these examinations which are under review at the Appeals level. We believe Regency will prevail against this challenge by the IRS. Accordingly, no unrecognized tax benefit has been recorded with respect to these tax positions. The proposed adjustments with respect to Regency would not have a material impact upon our financial statements.
ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.
Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefit of $1.81 billion in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

12.11.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus
Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of

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litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011.
On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011.
FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs.
Contingent Residual Support Agreement —– AmeriGas
In connection with the closing of the contribution of ETP’sits propane operations in January 2012, ETP agreed to providepreviously provided contingent residual support of $1.55 billioncertain debt obligations of intercompany borrowings made byAmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and certain of its affiliates with maturities through 2022 from a finance subsidiary ofETP no longer provides contingent residual support for any AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchases.notes.
PEPL Holdings Guarantee of CollectionSunoco LP Notes
In connection with the SUGS Contribution, Regency issued $600previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 4.50%6.375% senior notes due 2023( issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portionassignment of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basisSunoco LP’s senior notes, to Southern Union) to Regencyits subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and Regency Energy Finance Corp.issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of theprincipal amounts:
$1.00 billion aggregate principal amount of the Regency Debt through maturity in 2023. In connection with the completion4.875%, senior notes due 2023;
$800 million aggregate principal amount of the Panhandle Merger, in which PEPL Holdings was merged with5.50% senior notes due 2026; and into Panhandle,
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, forETC M-A would have the Regency Debt was assumed by Panhandle.
NGL Pipeline Regulation
Weobligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have interestsfirst been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in NGL pipelines located in Texas and New Mexico. We commencedrespect of the interstate transportationprincipal of NGLs in 2013, which issuch notes. ETC M-A will not otherwise be subject to the jurisdictioncovenants of the indenture governing the notes.
FERC underAudit
In March 2016, the Interstate Commerce Act (“ICA”)FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference.FERC’s annual reporting requirements. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.
Transwestern Rate Case
On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to the 2011 settlement agreement with its shippers.  On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in August 2015.
FGT Rate Case
On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015.audit is ongoing.
Commitments
In the normal course of business, ETP purchases, processes and Regency purchase, process and sellsells natural gas pursuant to long-term contracts and enterenters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

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We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
  Years Ended December 31,
  2014 2013 2012
Rental expense(1)
 $159
 $151
 $60
Less: Sublease rental income (26) (24) (4)
Rental expense, net $133
 $127
 $56
(1)
Includes contingent rentals totaling $24 million, $22 million and $6 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Future minimum lease commitments for such leases are:
Years Ending December 31: 
2015$151
2016129
2017118
2018108
2019102
Thereafter829
Future minimum lease commitments1,437
Less: Sublease rental income(34)
Net future minimum lease commitments$1,403
ETP and Regency’sETP’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
  Years Ended December 31,
  2017 2016 2015
Rental expense(1)
 $196
 $187
 $281
Less: Sublease rental income (25) (26) (26)
Rental expense, net $171
 $161
 $255
(1)
Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Future minimum lease commitments for such leases are:
Years Ending December 31: 
2018$113
2019100
202096
202183
202271
Thereafter606
Future minimum lease commitments1,069
Less: Sublease rental income(152)
Net future minimum lease commitments$917
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
Dakota Access Pipeline
On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.
After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.
The SRST appealed the denial of the preliminary injunction to the United States Court of Appeals for the D.C. Circuit and filed an emergency motion in the United States District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.
In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the Tribe. The District Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.

The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes.
On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018.
On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access is required to file the revised plan with the Court by April 1, 2018. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first report was filed with the court on December 29, 2017.
In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. Briefing on YST’s motion is ongoing.
While we believe that the pending lawsuits are unlikely to halt or suspend the operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.
MTBE Litigation
Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other refiners, manufacturers and sellersmembers of gasoline, is a defendantthe petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, typically include water purveyors and municipalities responsible for supplying drinking water andstate-level governmental authorities. The plaintiffs are asserting primarilyentities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, andand/or deceptive business practices. The plaintiffs in all of the cases are seekingseek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2014,2017, Sunoco, Inc. is a defendant in fiveseven cases, including casesone case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two others by the Commonwealth of Puerto Rico with theRico. The more recent Puerto Rico action beingis a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are venuedpending in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico,court; one is

pending in federal court in Rhode Island, one is pending in state court in Vermont, and Pennsylvania cases assert natural resource damage claims.one is pending in state court in Maryland.

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Fact discovery has concluded with respect to an initial set of 19 sites each that will beNew Jersey. The Court approved the subjectJudicial Consent Order on December 5, 2017. Dismissal of the first trial phase in the New Jersey case and the initial Puerto Rico case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claims to provide an analysis of the ultimate potential liability ofagainst Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in these matters. December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized;realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that anAn adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any saidsuch adverse determination occurs, but does not believe that any such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Regency Merger Litigation Relating
Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the PVR Merger
Five putativeRegency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action lawsuits challenging the PVR Acquisition are currently pending. All of these cases name PVR, PVRcomplaint, Dieckman v. Regency GP and the current directors of PVR GP, as well as the Partnership and the General Partner (collectively, the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in the alleged breach of these fiduciary duties, and, as to the actions in federal court, that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in general, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) in the event the merger is consummated, rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly causes by the defendants to these actions, and, (iv) such further relief as the court deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P.,LP, et al. (Case, C.A. No. 9015-VCL)11130-CB, in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. (Case No. 2013-10606)Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and Saul Srour v. PVR Partners, L.P., et al. (Case No. 2013-011015), each pendingthe members of Regency’s board of directors (the “Regency Litigation Defendants”).
The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-06829-HB);Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and Mark Hinnau v. PVR Partners, L.P., et al. (C.A. No. 2:13-cv-07496-HB), pending in the United States District Court for the Eastern District of Pennsylvania.
a Motion to Stay Discovery on May 19, 2017. On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, completion of certain confirmatory discovery, class certification and final approval byFebruary 20, 2018, the Court of Common Pleas for Delaware County, Pennsylvania. IfChancery issued an Order granting in part and denying in part the Court approvesmotions to dismiss, dismissing the settlement,claims against all defendants other than Regency GP, LP and Regency GP LLC.
The Regency Litigation Defendants cannot predict the Settled Lawsuitsoutcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and expense that will be dismissedrequired to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits.
The settlement will not affect any provisions of the merger agreement or the form or amount of consideration to be received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation.
Eagle Rock Shareholder Litigation
Three putative class action lawsuits challenging the Eagle Rock Midstream Acquisition are currently pending in federal district court in Houston, Texas. All cases name Eagle Rock and its current directors, as well as the Partnership and a subsidiary, as defendants. One of the lawsuits also names additional Eagle Rock entities as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock. The Plaintiffs in each case seek to rescind the transaction, claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. Plaintiffs also seek monetary damages and attorneys’ fees. Regency and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board.Merger.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise has filed a notice of appeal. appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP filed a petition for review with the Texas Supreme Court. Enterprise’s response is due February 26, 2018.
Sunoco Logistics Merger Litigation
Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In accordancere Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with GAAP,

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Tablethe Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of Contentsthe Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well


no amountsas an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017.
The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger.
Litigation Filed By or Against Williams
On April 6, 2016, Williams filed a complaint, The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.
On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions.
ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the original verdictmerger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.
After a two-day trial on June 20 and 21, 2016, the JulyCourt ruled in favor of ETE on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.
Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Defendants breached an additional representation and warranty in the Merger Agreement.
Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On

September 29, 2014 final judgment2016, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016.
On March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial and denied Williams’ motion for reargument on April 5, 2017. As a result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.
Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be recordedrequired to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.
Unitholder Litigation Relating to the Issuance
In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in our financial statements until the appeal processDelaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.
The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.
The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is completed.currently set for February 19-21, 2018.
The Issuance Defendants cannot predict the outcome of the Issuance Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation. The Issuance Defendants believe the Issuance Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Issuance.
Litigation filed by BP Products
On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.
SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.
On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.
Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 20142017 and 2013,2016, accruals of approximately $37$33 million and $46$77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
No amounts have been recorded in our December 31, 20142017 or 20132016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Attorney General of the Commonwealth of Massachusetts v New England Gas Company
On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries. The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities. In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including: (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery. Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of Southern Union’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted.  By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the applicability of attorney-client privilege to legal billing invoices.  The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.
Air Quality Control
SUGS is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three SUGS recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard.
Compliance Orders from the New Mexico Environmental Department
SUGS has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until March 2014 to allow the parties to pursue substantive settlement discussions. SUGS has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. SUGS has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses.

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Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believeHistorically, our environmental compliance costs have not had a material adverse effect on our results of operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result,but there can be no assurance that significantsuch costs and liabilities will not be incurred.material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million

for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Currently operating Sunoco, Inc. retail sites.
Legacy sites related to Sunoco, Inc., that are subject to environmental assessments, includeincluding formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2014,2017, Sunoco, Inc. had been named as a PRP at approximatelapproximaty 51ely 43 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

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The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
December 31,December 31,
2014 20132017 2016
Current$41
 $47
$35
 $26
Non-current360
 356
337
 318
Total environmental liabilities$401
 $403
$372
 $344

In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the years ended December 31, 20142017 and 2013,2016, the Partnership recorded $48$32 million and $41$43 million, respectively, of expenditures related to environmental cleanup programs.
On June 29, 2011,December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the U.S. Environmental Protection Agency finalizedToledo Refinery to Toledo Refining Company LLC (TRC) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period.  On January 2, 2013, USEPA issued a rule under theFinding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations.  To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that revisedSunoco, Inc. operated the new source performance standardsrefinery.  Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for manufacturers, ownersminimizing emissions and/or in conformance with their design, and operatorsthat Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of new, modifiedthe information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and reconstructed stationary internal combustion engines.discussions continue between the parties. The rule became effective on August 29, 2011. The rule modifications may require ustiming or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipmentbe a material impact to its results of operations, cash flows or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.financial position.
Our pipeline operations are subject to regulation by the U.S.United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
In January 2012, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas.  The proposed penalties are in excess of $100,000. The case went to hearing in November 2016 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.

In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’sOccupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with thepast costs for OSHA requirements,required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
13.12.PRICE RISK MANAGEMENTDERIVATIVE ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, our subsidiarieswe utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. Following is a description of price risk management activities by operating entity.
ETP
ETP injectsWe use futures and holdsbasis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in itsour Bammel storage facility to take advantage of contango markets (i.e., when the price of natural gas is higher in the future than the current spot price). ETP uses financial derivatives tofacility. At hedge the natural gas held

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in connection with these arbitrage opportunities. At the inception, of the hedge, ETP lockswe lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract to lock in the sale price. If ETP designates the related financial contract as a fair value hedge for accounting purposes, ETP values the hedged natural gas inventory at current spot market prices along with the financial derivative ETP uses to hedge it.contract. Changes in the spreadspreads between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent
We use futures, swaps and options to hedge the unrealized gains or losses from ETP’s derivative instruments using mark-to-market accounting, with changes in the fair valuesales price of our derivatives being recorded directly in earnings. These margins fluctuate based upon changes in the spreads between the physical spot price and forward natural gas prices. If the spread narrows between the physical and financial prices, ETP will record unrealized gains or lower unrealized losses. If the spread widens, ETP will record unrealized losses or lower unrealized gains. Typically, as ETP enters the winter months, the spread converges so that ETP recognizes in earnings the original locked-in spread through either mark-to-market adjustments or the physical withdraw of natural gas.
ETP is also exposed to market risk on natural gas it retainswe retain for fees in itsour intrastate transportation and storage operations and operational gas sales on itsour interstate transportation and storage operations. ETP uses financial derivativesThese contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge theforecasted sales price of this gas, including futures, swapsNGL and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted sale of natural gas. The change in value, to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.
ETP is also exposed to commodity price risk on NGLs and residue gas it retainscondensate equity volumes we retain for fees in itsour midstream operations whereby itsour subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGLs. ETP uses NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes. Certain contracts that qualify for hedge accounting are accounted for as cash flow hedges. The change in value, to the extent theNGL. These contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivative is recorded in cost of products sold in the consolidated statement of operations.not designated as hedges for accounting purposes.
ETP may use derivatives in ETP’s liquids transportation and services operations to manage ETP’s storage facilities and the purchase and sale of purity NGLs.
Sunoco Logistics utilizes derivatives such asWe utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs.NGLs to manage our storage facilities and the purchase and sale of purity NGL. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties who are able and willing to bear it. Since the first quarter 2013, Sunoco Logistics has not designated any of its derivative contracts as hedges for accounting purposes. Therefore, all realized
We use futures and unrealized gains and losses from these derivative contracts are recognized in the consolidated statements of operations during the current period.
ETP also uses derivatives to hedge a variety of price risks in its retail marketing operations. Futures and swaps are used to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs. The derivatives usedcosts in ETP’sour retail marketing operations represent economic hedges; however, ETP has elected not to designate any of the hedges in these operations. Therefore, all realized and unrealized gains and losses from these derivativeThese contracts are recognized in the consolidated statements of operations during the current period.not designated as hedges for accounting purposes.
ETP’s trading activities include theWe use of financial commodity derivatives to take advantage of market opportunities. Theseopportunities in our trading activities are awhich complement to itsour transportation and storage operationsoperations’ and are netted in cost of products sold in theour consolidated statements of operations. Additionally, ETPWe also hashave trading and marketing activities related to power and natural gas in itsour all other operations which are also netted in cost of products sold. As a result of itsour trading activities and the use of derivative financial instruments in itsour transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. ETP attemptsWe attempt to manage this volatility through the use of daily position and profit and loss reports provided to itsour risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in ETP’sour commodity risk management policy.

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The following table details ETP’sour outstanding commodity-related derivatives: 
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Notional
Volume
 Maturity 
Notional
Volume
 Maturity
Notional
Volume
 Maturity 
Notional
Volume
 Maturity
Mark-to-Market Derivatives        
(Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Fixed Swaps/Futures(232,500) 2015 9,457,500
 2014-20191,078
 2018 (683) 2017
Basis Swaps IFERC/NYMEX (1)
(13,907,500) 2015 - 2016 (487,500) 2014-201748,510
 2018-2020 2,243
 2017
Swing Swaps—
 — 1,937,500
 2014-2016
Options – Calls5,000,000
 2015 —
 —
Options – Puts13,000
 2018 —
 —
Power (Megawatt):        
Forwards288,775
 2015 351,050
 2014435,960
 2018-2019 391,880
 2017 - 2018
Futures(156,000) 2015 (772,476) 2014(25,760) 2018 109,564
 2017 - 2018
Options — Puts(72,000) 2015 (52,800) 2014(153,600) 2018 (50,400) 2017
Options — Calls198,556
 2105 103,200
 2014137,600
 2018 186,400
 2017
Crude (Bbls) – Futures—
 — 103,000
 2014
Crude (MBbls) – Futures—
 — (617) 2017
(Non-Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Basis Swaps IFERC/NYMEX57,500
 2015 570,000
 20144,650
 2018-2020 10,750
 2017 - 2018
Swing Swaps IFERC46,150,000
 2015 (9,690,000) 2014-201687,253
 2018-2019 (5,663) 2017
Fixed Swaps/Futures(8,779,000) 2015 - 2016 (8,195,000) 2014-2015(4,390) 2018-2019 (52,653) 2017 - 2019
Forward Physical Contracts(9,116,777) 2015 5,668,559
 2014-2015(145,105) 2018-2020 (22,492) 2017
Natural Gas Liquid (Bbls) – Forwards/Swaps(2,179,400) 2015 (1,133,600) 2014
Refined Products (Bbls) – Futures13,745,755
 2015 (280,000) 2014
Natural Gas Liquid (MBbls) – Forwards/Swaps6,744
 2018-2019 (5,787) 2017
Refined Products (MBbls) – Futures(3,901) 2018-2019 (3,144) 2017
Corn (Bushels) – Futures1,870,000
 2018 1,580,000
 2017
Fair Value Hedging Derivatives        
(Non-Trading)        
Natural Gas (MMBtu):    
Natural Gas (BBtu):    
Basis Swaps IFERC/NYMEX(39,287,500) 2015 (7,352,500) 2014(39,770) 2018 (36,370) 2017
Fixed Swaps/Futures(39,287,500) 2015 (50,530,000) 2014(39,770) 2018 (36,370) 2017
Hedged Item — Inventory39,287,500
 2015 50,530,000
 201439,770
 2018 36,370
 2017
Cash Flow Hedging Derivatives    
(Non-Trading)    
Natural Gas (MMBtu):    
Basis Swaps IFERC/NYMEX—
 — (1,825,000) 2014
Fixed Swaps/Futures—
 — (12,775,000) 2014
Natural Gas Liquid (Bbls) – Forwards/Swaps—
 — (780,000) 2014
Crude (Bbls) – Futures—
 — (30,000) 2014
(1) 
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.

Regency
Regency is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in the supply and demand as well as market forces. Regency’s profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect its ability to make distributions to its unitholders. Regency manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by

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monitoring basis and other price differentials in operating areas and the use of derivative contracts. In some cases, Regency may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.
Marketing & Trading. Regency conducts natural gas marketing and trading activities through its Logistics and Trading subsidiary. Regency engages in activities intended to capitalize on favorable price differentials between various receipt and delivery locations. Regency enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchase and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales and realized (unrealized) gain (loss) from derivatives, as appropriate.
Through its natural gas marketing activity, Regency has credit exposure to additional counterparties. Regency minimizes the credit risk associated with natural gas marketing by limiting its exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, Regency’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, Regency nets the open positions of each counterparty.
Regency is exposed to market risks associated with commodity prices, counterparty credit, and interest rates. Regency’s management and the board of directors of Regency GP have established comprehensive risk management policies and procedures to monitor and manage these market risks. Regency GP is responsible for delegation of transaction authority levels, and the Audit and Risk Committee of Regency GP is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. Regency GP’s Audit and Risk Committee receives regular briefings on positions and exposures, credit exposures, and overall risk management in the context of market activities.
Regency’s Preferred Units (see Note 7) contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and Regency’s call option. These embedded derivatives are accounted for using mark-to-market accounting. Regency does not expect the embedded derivatives to affect its cash flows.
The following table details Regency’s outstanding commodity-related derivatives:
 December 31, 2014 December 31, 2013
 
Notional
Volume
 Maturity 
Notional
Volume
 Maturity
Mark-to-Market Derivatives       
(Non-Trading)       
Natural Gas (MMBtu) — Fixed Swaps/Futures(25,525,000) 2015 (24,455,000) 2014-2015
Propane (Gallons) — Forwards/Swaps(29,148,000) 2015 (52,122,000) 2014-2015
NGLs (Barrels) — Forwards/Swaps(292,000) 2015 (438,000) 2014
WTI Crude Oil (Barrels) — Forwards/Swaps(1,252,000) 2015-2016 (521,000) 2014
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

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The following table summarizes our interest rate swaps outstanding, none of which are designated as hedges for accounting purposes:
     Notional Amount Outstanding     Notional Amount Outstanding
Entity Term 
Type(1)
 December 31,
2014		 December 31,
2013		 Term 
Type(1)
 December 31, 2017 December 31, 2016
ETP 
July 2014(2)
 Forward-starting to pay a fixed rate of 4.25% and receive a floating rate $—
 $400
 
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
ETP 
July 2015(2)
 Forward-starting to pay a fixed rate of 3.38% and receive a floating rate 200
 —
 
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
ETP 
July 2016(3)
 Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 200
 —
 
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
ETP 
July 2017(4)
 Forward-starting to pay a fixed rate of 3.84% and receive a floating rate 300
 —
 
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
ETP 
July 2018(4)
 Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200
 —
 December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
ETP 
July 2019(4)
 Forward-starting to pay a fixed rate of 3.19% and receive a floating rate 300
 —
 March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
ETP July 2018 Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% —
 600
ETP June 2021 Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% —
 400
ETP February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% 200
 400
Panhandle November 2021 Pay a fixed rate of 3.82% and receive a floating rate —
 275
(1) 
Floating rates are based on 3-month LIBOR.
(2) 
Represents the effective date. These forward-starting swaps have a term of 10 years with a mandatory termination date the same as the effective date.
(3)
Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
(4)
Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern ETP’sthe Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, ETPthe Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. ETPThe Partnership also implements the use ofuses industry standard commercial agreements which allow for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, ETP utilizeswe utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
ETP’sThe Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies, and midstream companies. ETP’sindependent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact itsour counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
ETPThe Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds itsour pre-established

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credit limit with the counterparty. Margin deposits are returned to ETPus on or about the settlement date for non-exchange traded derivatives, and ETP exchangeswe exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
Regency is exposed to credit risk from its derivative counterparties. Regency does not require collateral from these counterparties as it deals primarily with financial institutions when entering into financial derivatives, and enters into master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If Regency’s counterparties failed to perform under existing swap contracts, Regency’s maximum loss as of December 31, 2014 would be $82 million, which would be reduced by less than $1 million due to the netting feature. Regency has elected to present assets and liabilities under master netting agreements gross on the condensed consolidated balance sheets for it derivate contracts outside of its marketing and trading operations.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary
The following table provides a summary of our derivative assets and liabilities: 
Fair Value of Derivative InstrumentsFair Value of Derivative Instruments
Asset Derivatives Liability DerivativesAsset Derivatives Liability Derivatives
December 31, 2014 December 31, 2013 December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives designated as hedging instruments:              
Commodity derivatives (margin deposits)$43
 $3
 $—
 $(18)$14
 $—
 $(2) $(4)
43
 3
 —
 (18)14
 —
 (2) (4)
Derivatives not designated as hedging instruments:              
Commodity derivatives (margin deposits)$617
 $227
 $(577) $(209)262
 338
 (281) (416)
Commodity derivatives107
 43
 (23) (48)45
 25
 (58) (58)
Interest rate derivatives3
 47
 (155) (95)—
 —
 (219) (193)
Embedded derivatives in Regency Preferred Units—
 —
 (16) (19)
Embedded derivatives in ETP Convertible Preferred Units—
 —
 —
 (1)
727
 317
 (771) (371)307
 363
 (558) (668)
Total derivatives$770
 $320
 $(771) $(389)$321
 $363
 $(560) $(672)

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The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
 Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives
 Balance Sheet Location December 31, 2014 December 31, 2013 December 31, 2014 December 31, 2013 Balance Sheet Location December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives without offsetting agreements Derivative assets (liabilities) $—
 $—
 $(219) $(194)
Derivatives in offsetting agreements:Derivatives in offsetting agreements:        Derivatives in offsetting agreements:        
OTC contracts Price risk management assets (liabilities) $23
 $42
 $(23) $(38) Derivative assets (liabilities) 45
 25
 (58) (58)
Broker cleared derivative contracts Other current assets 674
 264
 (574) (318) Other current assets (liabilities) 276
 338
 (283) (420)
 697
 306
 (597) (356)  321
 363
 (560) (672)
Offsetting agreements:Offsetting agreements:        Offsetting agreements:        
Counterparty netting Price risk management assets (liabilities) (19) (36) 19
 36
 Derivative assets (liabilities) (21) (4) 21
 4
Payments on margin deposit Other current assets 5
 (1) (22) 55
 (14) (37) (3) 91
Net derivatives with offsetting agreements 683
 269
 (600) (265)
Derivatives without offsetting agreements 87
 51
 (171) (124)
Total derivatives $770
 $320
 $(771) $(389)
Counterparty netting Other current assets (liabilities) (263) (338) 263
 338
Total net derivativesTotal net derivatives $37
 $21
 $(276) $(330)
We disclose the non-exchange traded financial derivative instruments as price risk managementderivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to our derivative financial instruments:
Change in Value Recognized in OCI
on Derivatives (Effective Portion)
Location of Gain/(Loss)
Recognized in
Income on Derivatives
 
Amount of Gain/(Loss) Recognized in Income
Representing Hedge Ineffectiveness and
Amount Excluded from the Assessment of
Effectiveness
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Derivatives in cash flow hedging relationships:     
Derivatives in fair value hedging relationships (including hedged item):      
Commodity derivatives$—
 $(1) $8
Cost of products sold $26
 $14
 $21
Total$—
 $(1) $8
 $26
 $14
 $21
 
Location of
Gain/(Loss) Reclassified
from AOCI into Income
(Effective Portion)
 
Amount of Gain/(Loss) Reclassified from
AOCI into Income (Effective Portion)
 Years Ended December 31,
 2014 2013 2012
Derivatives in cash flow hedging relationships:       
Commodity derivativesCost of products sold $(3) $4
 $14
Total  $(3) $4
 $14
 Location of Gain/(Loss) Recognized in Income on Derivatives 
Amount of Gain/(Loss) Recognized
in Income on Derivatives
  Years Ended December 31,
  2017 2016 2015
Derivatives not designated as hedging instruments:       
Commodity derivatives – TradingCost of products sold $31
 $(35) $(11)
Commodity derivatives – Non-tradingCost of products sold 5
 (177) 15
Interest rate derivativesLosses on interest rate derivatives (37) (12) (18)
Embedded derivativesOther, net 1
 4
 12
Total  $—
 $(220) $(2)


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Location of Gain/(Loss)
Recognized in
Income on Derivatives
 
Amount of Gain/(Loss) Recognized in Income
Representing Hedge Ineffectiveness and
Amount Excluded from the Assessment of
Effectiveness
 Years Ended December 31,
 2014 2013 2012
Derivatives in fair value hedging relationships (including hedged item):       
Commodity derivativesCost of products sold $(8) $8
 $54
Total  $(8) $8
 $54
 Location of Gain/(Loss) Recognized in Income on Derivatives 
Amount of Gain/(Loss) Recognized
in Income on Derivatives
  Years Ended December 31,
  2014 2013 2012
Derivatives not designated as hedging instruments:       
Commodity derivatives – TradingCost of products sold $(6) $(11) $(7)
Commodity derivatives – Non-tradingCost of products sold 199
 (21) 26
Commodity contracts – Non-tradingDeferred gas purchases —
 (3) (26)
Interest rate derivativesGains (losses) on interest rate derivatives (157) 53
 (19)
Embedded derivativesOther income 3
 6
 14
Total  $39
 $24
 $(12)

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14.13.RETIREMENT BENEFITS:
Savings and Profit Sharing Plans
We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETP, RegencySunoco LP and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $59$38 million, $47$44 million and $30$40 million to the 401(k) savings plan for the years ended December 31, 2014, 20132017, 2016, and 2012,2015, respectively.
Pension and Other Postretirement Benefit Plans
Panhandle
Postretirement benefits expense for the years ended December 31, 2017, 2016, and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that were available tocovered substantially all of its employees, pendingemployees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree meeting certain age and service requirements.medical benefits were no longer offered to union employees.
Sunoco, Inc.
Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and anticipates approval for the distribution of assets from the plan, pending approval from the Pension Benefit Guaranty Corporationpaid lump sums to eligible active and the IRS,terminated vested participants in the fourth quarter ofDecember 2015.
Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200$200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.

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The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Pension Benefits   Pension Benefits  Pension Benefits   Pension Benefits  
Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement BenefitsFunded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Change in benefit obligation:                      
Benefit obligation at beginning of period$632
 $61
 $223
 $1,117
 $78
 $296
$18
 $51
 $166
 $20
 $57
 $181
Service cost—
 —
 —
 3
 —
 —
Interest cost28
 3
 5
 33
 2
 6
1
 1
 4
 1
 2
 4
Amendments—
 —
 1
 —
 —
 2
—
 —
 7
 —
 —
 —
Benefits paid, net(45) (9) (28) (99) (16) (26)(2) (6) (20) (1) (7) (21)
Actuarial (gain) loss and other130
 10
 2
 (74) (3) (14)2
 1
 (1) (2) (1) 2
Settlements(27) —
 —
 (95) —
 —
(18) —
 —
 —
 —
 —
Dispositions—
 —
 —
 (253) —
 (41)
Benefit obligation at end of period$718
 $65
 $203
 $632
 $61
 $223
$1
 $47
 $156
 $18
 $51
 $166
                      
Change in plan assets:                      
Fair value of plan assets at beginning of period600
 —
 284
 906
 —
 312
$12
 $—
 $256
 $15
 $—
 $261
Return on plan assets and other70
 —
 7
 43
 —
 17
3
 —
 11
 (2) —
 6
Employer contributions—
 —
 9
 —
 —
 8
6
 —
 10
 —
 —
 10
Benefits paid, net(45) —
 (28) (99) —
 (26)(2) —
 (20) (1) —
 (21)
Settlements(27) —
 —
 (95) —
 —
(18) —
 —
 —
 —
 —
Dispositions—
 —
 —
 (155) —
 (27)
Fair value of plan assets at end of period$598
 $—
 $272
 $600
 $—
 $284
$1
 $—
 $257
 $12
 $—
 $256
                      
Amount underfunded (overfunded) at end of period$120
 $65
 $(69) $32
 $61
 $(61)$—
 $47
 $(101) $6
 $51
 $(90)
                      
Amounts recognized in the consolidated balance sheets consist of:                      
Non-current assets$—
 $—
 $96
 $—
 $—
 $86
$—
 $—
 $127
 $—
 $—
 $114
Current liabilities—
 (9) (2) —
 (9) (2)—
 (8) (2) —
 (7) (2)
Non-current liabilities(120) (56) (25) (32) (52) (23)—
 (39) (24) (6) (44) (23)
$(120) $(65) $69
 $(32) $(61) $61
$—
 $(47) $101
 $(6) $(51) $89
                      
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:                      
Net actuarial gain$18
 $7
 $(21) $(86) $(4) $(25)$—
 $5
 $(18) $—
 $—
 $(13)
Prior service cost—
 —
 18
 —
 —
 18
—
 —
 21
 —
 —
 15
$18
 $7
 $(3) $(86) $(4) $(7)$—
 $5
 $3
 $—
 $—
 $2

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The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Pension Benefits   Pension Benefits  Pension Benefits   Pension Benefits  
Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement BenefitsFunded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Projected benefit obligation$718
 $65
 N/A
 $632
 61
 N/A
$1
 $47
 N/A
 $18
 $51
 N/A
Accumulated benefit obligation718
 65
 203
 632
 61
 $223
1
 47
 $156
 18
 51
 $166
Fair value of plan assets598
 —
 272
 600
 —
 284
1
 —
 257
 12
 —
 256
Components of Net Periodic Benefit Cost
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement BenefitsPension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Net Periodic Benefit Cost:              
Service cost$—
 $—
 $3
 $—
Interest cost31
 5
 35
 6
$2
 $4
 $3
 $4
Expected return on plan assets(40) (8) (54) (9)—
 (9) (1) (8)
Prior service cost amortization—
 1
 —
 1
—
 2
 —
 1
Actuarial loss amortization(1) (1) 2
 —
Settlements(4) —
 (2) —
(14) (3) (16) (2)
Regulatory adjustment(1)
—
 —
 5
 —
Net periodic benefit cost$(14) $(3) $(11) $(2)$2
 $(3) $2
 $(3)
(1)
Southern Union, the predecessor of Panhandle, historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its distribution operation.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement BenefitsPension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.62% 2.24% 4.65% 2.33%3.27% 2.34% 3.65% 2.34%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
N/A
 N/A
 N/A
 N/A

F - 76

The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement BenefitsPension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate4.65% 3.02% 3.50% 2.68%3.52% 3.10% 3.60% 3.06%
Expected return on assets:              
Tax exempt accounts7.50% 7.00% 7.50% 6.95%3.50% 7.00% 3.50% 7.00%
Taxable accountsN/A
 4.50% N/A
 4.42%N/A
 4.50% N/A
 4.50%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
N/A
 N/A
 N/A
 N/A
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest

rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:
December 31,December 31,
2014 20132017 2016
Health care cost trend rate7.09% 7.57%7.20% 6.73%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)5.41% 5.42%4.99% 4.96%
Year that the rate reaches the ultimate trend rate2018
 2018
2023
 2021
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of up to 10%. 
The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.
The fair value of the pension plan assets by asset category at the dates indicated is as follows:
   Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy   Fair Value Measurements at December 31, 2017
 Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Fair Value Total Level 1 Level 2 Level 3
Asset Category:                
Cash and cash equivalents $25
 $25
 $—
 $—
Mutual funds (1)
 110
 —
 110
 —
 $1
 $1
 $—
 $—
Fixed income securities 463
 —
 463
 —
Total $598
 $25
 $573
 $—
 $1
 $1
 $—
 $—

F - 77

(1)
Comprised of 100% equities as of December 31, 2014.2017.
   Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy   Fair Value Measurements at December 31, 2016
 Fair Value as of December 31, 2013 Level 1 Level 2 Level 3 Fair Value Total Level 1 Level 2 Level 3
Asset Category:                
Cash and cash equivalents $12
 $12
 $—
 $—
Mutual funds (1)
 368
 —
 281
 87
 $12
 $12
 $—
 $—
Fixed income securities 220
 —
 220
 —
Total $600
 $12
 $501
 $87
 $12
 $12
 $—
 $—
(1) 
Primarily comprisedComprised of approximately 41%100% equities 45% fixed income securities, and 14% in other investments as of December 31, 2013.2016.

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
   Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy   Fair Value Measurements at December 31, 2017
 Fair Value as of December 31, 2014 Level 1 Level 2 Level 3 Fair Value Total Level 1 Level 2 Level 3
Asset Category:                
Cash and Cash Equivalents $9
 $9
 $—
 $—
 $33
 $33
 $—
 $—
Mutual funds (1)
 138
 138
 —
 —
 154
 154
 —
 —
Fixed income securities 125
 —
 125
 —
 70
 —
 70
 —
Total $272
 $147
 $125
 $—
 $257
 $187
 $70
 $—
(1)
Primarily comprised of approximately 53%38% equities, 41%61% fixed income securities 6%and 2% cash as of December 31, 2014.2017.
   Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy   Fair Value Measurements at December 31, 2016
 Fair Value as of December 31, 2013 Level 1 Level 2 Level 3 Fair Value Total Level 1 Level 2 Level 3
Asset Category:                
Cash and Cash Equivalents $10
 $10
 $—
 $—
 $23
 $23
 $—
 $—
Mutual funds (1)
 130
 112
 18
 —
 142
 142
 —
 —
Fixed income securities 144
 —
 144
 —
 91
 —
 91
 —
Total $284
 $122
 $162
 $—
 $256
 $165
 $91
 $—
(1) 
Primarily comprised of approximately 41%31% equities, 48%66% fixed income securities and 6%3% cash and 5% in other investments as of December 31, 2013.2016.
The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  See Note 2for information related to the framework used to measure the fair value of its pension and other postretirement plan assets.
Contributions
We expect to contribute approximately $129$8 million to pension plans and approximately $10 million to other postretirementpostretirement plans in 2015.2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

F - 78

Benefit Payments
Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:
  Pension Benefits  
Years Funded Plans Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D)
2015 $717
 $9
 $28
2016 —
 8
 26
2017 —
 7
 25
2018 —
 7
 23
2019 —
 6
 22
2020 – 2024 —
 23
 65
Years 
Pension Benefits - Unfunded Plans (1)
 Other Postretirement Benefits (Gross, Before Medicare Part D)
2018 $8
 $24
2019 6
 23
2020 6
 21
2021 5
 19
2022 4
 17
2023 – 2027 15
 37
(1)     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

15.14.RELATED PARTY TRANSACTIONS:
The Parent Company has agreements with subsidiaries to provide or receive various generalIn June 2017, ETP acquired all of the publicly held PennTex common units through a tender offer and administrative services. The Parent Company paysexercise of a limited call right, as further discussed in Note 8.
ETE previously paid ETP to provide services on its behalf and theon behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries,ETE, which includeincluded the reimbursement of various operating and general and administrative services for expenses incurred by ETP on behalf of thoseETE and its subsidiaries. All such amounts have been eliminatedThese agreements expired in our consolidated financial statements.
In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 16).2016.
In addition, subsidiaries of ETE recorded sales with affiliates of $965$303 million, $1.44 billion$221 million and $189$290 million during the years ended December 31, 2014, 20132017, 2016 and 2012,2015, respectively.
16.15.REPORTABLE SEGMENTS:
AsSubsequent to ETE’s acquisition of a result of the Lake Charles LNG Transactioncontrolling interest in 2014,Sunoco LP, our reportable segments were re-evaluated and currentlyfinancial statements reflect the following reportable segments, which conduct their business exclusively in the United States, as follows:segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Regency,Sunoco LP, including the consolidated operations of Regency;Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
Related party transactions among our segments are generally based on transactions made at market-related rates. Consolidated revenues and expensesETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of all material intercompany transactions.MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.
We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losslosses on extinguishmentextinguishments of debt gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and

F - 79

inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership and amounts for less than wholly owned subsidiaries based on 100% of the subsidiaries’ results of operations. ownership.
Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.
Regency completed its acquisition of SUGS on April 30, 2013. Therefore, the investment in Regency segment amounts have been retrospectively adjusted to reflect SUGS beginning March 26, 2012.
Eliminations in the tables below include the following:
ETP’s Segment Adjusted EBITDA reflects 100% of Lone Star, which is a consolidated subsidiary of ETP. Regency’s Segment Adjusted EBITDA includes its 30% investment in Lone Star. Therefore, 30% of the results of Lone Star are included in eliminations.
ETP’s Segment Adjusted EBITDA reflects the results of SUGS from March 26, 2012 to April 30, 2013. Since the SUGS Contribution was a transaction between entities under common control, Regency’s results have been recast to retrospectively consolidate SUGS beginning March 26, 2012. Therefore, the eliminations also include the results of SUGS from March 26, 2012 to April 30, 2013.
ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG prior to the Lake Charles LNG Transaction, which was effective January 1, 2014. The Investment in Lake Charles LNG segment reflected the results of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segmentsMACS, Sunoco LLC, Susser and Sunoco Retail LLC for the years ended December 31, 2013 and 2012 beginning March 26, 2012. Therefore, the results of Lake Charles LNGperiods during which those entities were included in eliminations for 2013the consolidated results of both ETP and 2012.


F - 80

 Years Ended December 31,
 2014 2013 2012
Revenues:     
Investment in ETP:     
Revenues from external customers$50,989
 $46,210
 $15,671
Intersegment revenues169
 129
 31
 51,158
 46,339
 15,702
Investment in Regency:     
Revenues from external customers4,597
 2,404
 1,986
Intersegment revenues354
 117
 14
 4,951
 2,521
 2,000
Investment in Lake Charles LNG:     
Revenues from external customers216
 216
 166
 

 

 

Adjustments and Eliminations:(634) (741) (904)
Total revenues$55,691
 $48,335
 $16,964
      
Costs of products sold:     
Investment in ETP$45,540
 $41,204
 $12,266
Investment in Regency3,452
 1,793
 1,387
Adjustments and Eliminations(603) (443) (565)
Total costs of products sold$48,389
 $42,554
 $13,088
      
Depreciation, depletion and amortization:     
Investment in ETP1,130
 1,032
 656
Investment in Regency541
 287
 252
Investment in Lake Charles LNG39
 39
 30
Corporate and Other17
 16
 14
Adjustments and Eliminations(3) (61) (81)
Total depreciation, depletion and amortization$1,724
 $1,313
 $871
Sunoco LP, as discussed above.
 Years Ended December 31,
 2014 2013 2012
Equity in earnings of unconsolidated affiliates:     
Investment in ETP$234
 $172
 $142
Investment in Regency195
 135
 105
Adjustments and Eliminations(97) (71) (35)
Total equity in earnings of unconsolidated affiliates$332
 $236
 $212

F - 81

 Years Ended December 31,
 2014 2013 2012
Segment Adjusted EBITDA:     
Investment in ETP$4,829
 $3,953
 $2,744
Investment in Regency1,172
 608
 517
Investment in Lake Charles LNG195
 187
 135
Corporate and Other(97) (43) (52)
Adjustments and Eliminations(259) (338) (239)
Total Segment Adjusted EBITDA5,840
 4,367
 3,105
Depreciation, depletion and amortization(1,724) (1,313) (871)
Interest expense, net of interest capitalized(1,369) (1,221) (1,018)
Bridge loan related fees—
 —
 (62)
Gain on deconsolidation of Propane Business—
 —
 1,057
Gain on sale of AmeriGas common units177
 87
 —
Goodwill impairment(370) (689) —
Gains (losses) on interest rate derivatives(157) 53
 (19)
Non-cash unit-based compensation expense(82) (61) (47)
Unrealized gains on commodity risk management activities116
 48
 10
Losses on extinguishments of debt(25) (162) (123)
Inventory valuation adjustments(473) 3
 (75)
Adjusted EBITDA related to discontinued operations(27) (76) (99)
Adjusted EBITDA related to unconsolidated affiliates(748) (727) (647)
Equity in earnings of unconsolidated affiliates332
 236
 212
Non-operating environmental remediation—
 (168) —
Other, net(73) (2) 14
Income from continuing operations before income tax expense$1,417
 $375
 $1,437
 Years Ended December 31,
 2017 2016 2015
Revenues:     
Investment in ETP:     
Revenues from external customers$28,613
 $21,618
 $34,156
Intersegment revenues441
 209
 136
 29,054
 21,827
 34,292
Investment in Sunoco LP:     
Revenues from external customers11,713
 9,977
 12,419
Intersegment revenues10
 9
 11
 11,723
 9,986
 12,430
Investment in Lake Charles LNG:     
Revenues from external customers197
 197
 216
 

 

 

Adjustments and Eliminations:(451) (218) (10,842)
Total revenues$40,523
 $31,792
 $36,096
      
Costs of products sold:     
Investment in ETP$20,801
 $15,080
 $26,714
Investment in Sunoco LP10,615
 8,830
 11,450
Adjustments and Eliminations(450) (217) (9,496)
Total costs of products sold$30,966
 $23,693
 $28,668
      
Depreciation, depletion and amortization:     
Investment in ETP$2,332
 $1,986
 $1,929
Investment in Sunoco LP169
 176
 150
Investment in Lake Charles LNG39
 39
 39
Corporate and Other14
 15
 17
Adjustments and Eliminations—
 —
 (184)
Total depreciation, depletion and amortization$2,554
 $2,216
 $1,951
 December 31,
 2014 2013 2012
Total assets:     
Investment in ETP$48,221
 $43,702
 $43,230
Investment in Regency17,103
 8,782
 8,123
Investment in Lake Charles LNG1,210
 1,338
 1,917
Corporate and Other1,153
 720
 707
Adjustments and Eliminations(3,218) (4,212) (5,073)
Total$64,469
 $50,330
 $48,904

F - 82

 Years Ended December 31,
 2017 2016 2015
Equity in earnings of unconsolidated affiliates:     
Investment in ETP$156
 $59
 $469
Adjustments and Eliminations(12) 211
 (193)
Total equity in earnings of unconsolidated affiliates$144
 $270
 $276
 Years Ended December 31,
 2014 2013 2012
Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis):     
Investment in ETP$4,478
 $2,455
 $3,049
Investment in Regency1,112
 1,011
 599
Investment in Lake Charles LNG1
 2
 4
Adjustments and Eliminations(32) (126) (135)
Total$5,559
 $3,342
 $3,517

 December 31,
 2014 2013 2012
Advances to and investments in affiliates:     
Investment in ETP$3,840
 $4,436
 $3,502
Investment in Regency2,418
 2,097
 2,214
Adjustments and Eliminations(2,599) (2,519) (979)
Total$3,659
 $4,014
 $4,737
 Years Ended December 31,
 2017 2016 2015
Segment Adjusted EBITDA:     
Investment in ETP$6,712
 $5,733
 $5,517
Investment in Sunoco LP732
 665
 719
Investment in Lake Charles LNG175
 179
 196
Corporate and Other(31) (170) (104)
Adjustments and Eliminations(268) (272) (590)
Total Segment Adjusted EBITDA7,320
 6,135
 5,738
Depreciation, depletion and amortization(2,554) (2,216) (1,951)
Interest expense, net of interest capitalized(1,922) (1,804) (1,622)
Gains on acquisitions—
 83
 —
Impairment of investments in unconsolidated affiliates(313) (308) —
Impairment losses(1,039) (1,040) (339)
Losses on interest rate derivatives(37) (12) (18)
Non-cash unit-based compensation expense(99) (70) (91)
Unrealized gains (losses) on commodity risk management activities59
 (136) (65)
Losses on extinguishments of debt(89) —
 (43)
Inventory valuation adjustments24
 97
 (67)
Adjusted EBITDA related to discontinued operations(223) (199) (228)
Adjusted EBITDA related to unconsolidated affiliates(716) (675) (713)
Equity in earnings of unconsolidated affiliates144
 270
 276
Other, net155
 79
 23
Income from continuing operations before income tax benefit$710
 $204
 $900
Income tax benefit from continuing operations(1,833) (258) (123)
Income from continuing operations2,543
 462
 1,023
Income (loss) from discontinued operations, net of tax(177) (462) 38
Net income$2,366
 $—
 $1,061
 December 31,
 2017 2016 2015
Total assets:     
Investment in ETP$77,965
 $70,105
 $65,128
Investment in Sunoco LP8,344
 8,701
 8,842
Investment in Lake Charles LNG1,646
 1,508
 1,369
Corporate and Other598
 711
 638
Adjustments and Eliminations(2,307) (2,100) (4,833)
Total$86,246
 $78,925
 $71,144

 Years Ended December 31,
 2017 2016 2015
Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):     
Investment in ETP$5,901
 $5,810
 $8,167
Investment in Sunoco LP103
 119
 178
Investment in Lake Charles LNG2
 —
 1
Adjustments and Eliminations—
 —
 (123)
Total$6,006
 $5,929
 $8,223
 December 31,
 2017 2016 2015
Advances to and investments in affiliates:     
Investment in ETP$3,816
 $4,280
 $5,003
Adjustments and Eliminations(1,111) (1,240) (1,541)
Total$2,705
 $3,040
 $3,462
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Regency.Sunoco LP.
Investment in ETP
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Intrastate Transportation and Storage$2,652
 $2,250
 $2,012
$2,891
 $2,155
 $1,912
Interstate Transportation and Storage1,057
 1,270
 1,109
915
 946
 1,008
Midstream1,210
 1,307
 1,757
2,510
 2,342
 2,607
Liquids Transportation and Services3,790
 2,063
 619
Investment in Sunoco Logistics17,920
 16,480
 3,109
Retail Marketing22,484
 21,004
 5,926
NGL and refined products transportation and services8,326
 5,973
 4,569
Crude oil transportation and services11,672
 7,539
 8,980
All Other2,045
 1,965
 1,170
2,740
 2,872
 15,216
Total revenues51,158
 46,339
 15,702
29,054
 21,827
 34,292
Less: Intersegment revenues169
 129
 31
441
 209
 136
Revenues from external customers$50,989
 $46,210
 $15,671
$28,613
 $21,618
 $34,156
Investment in RegencySunoco LP
 Years Ended December 31,
 2014 2013 2012
Gathering and Processing$4,570
 $2,287
 $1,797
Contract Services307
 215
 183
Natural Gas Transportation—
 1
 1
Natural Resources58
 —
 —
Corporate and others16
 18
 19
Total revenues4,951
 2,521
 2,000
Less: Intersegment revenues354
 117
 14
Revenues from external customers$4,597
 $2,404
 $1,986
 Years Ended December 31,
 2017 2016 2015
Retail operations$2,263
 $1,991
 $2,226
Wholesale operations9,460
 7,995
 10,204
Total revenues11,723
 9,986
 12,430
Less: Intersegment revenues10
 9
 11
Revenues from external customers$11,713
 $9,977
 $12,419

F - 83

Investment in Lake Charles LNG
Lake Charles LNG’s revenues of $216$197 million, $216$197 million and $166$216 million for the yearyears ended December 31, 2014, 20132017, 2016 and 2012,2015, respectively, were related to LNG terminalling.

17.16.QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.
Quarters Ended  Quarters Ended  
March 31 June 30 September 30 December 31 Total YearMarch 31* June 30* September 30* December 31 Total Year
2014:         
2017:         
Revenues$13,080
 $14,143
 $14,987
 $13,481
 $55,691
$9,660
 $9,427
 $9,984
 $11,452
 $40,523
Gross margin1,638
 1,792
 1,972
 1,900
 7,302
Operating income710
 773
 822
 165
 2,470
Operating income (loss)758
 746
 924
 285
 2,713
Net income (loss)448
 500
 470
 (294) 1,124
319
 121
 758
 1,168
 2,366
Limited Partners’ interest in net income167
 163
 188
 111
 629
232
 204
 240
 239
 915
Basic net income per limited partner unit$0.30
 $0.30
 $0.35
 $0.21
 $1.16
$0.22
 $0.18
 $0.22
 $0.22
 $0.85
Diluted net income per limited partner unit$0.30
 $0.30
 $0.35
 $0.21
 $1.15
$0.21
 $0.18
 $0.22
 $0.22
 $0.83
 Quarters Ended  
 March 31 June 30 September 30 December 31 Total Year
2013:         
Revenues$11,179
 $12,063
 $12,486
 $12,607
 $48,335
Gross margin1,372
 1,498
 1,422
 1,489
 5,781
Operating income (loss)531
 644
 529
 (153) 1,551
Net income (loss)322
 338
 356
 (701) 315
Limited Partners’ interest in net income (loss)90
 127
 150
 (171) 196
Basic net income (loss) per limited partner unit$0.16
 $0.23
 $0.27
 $(0.31) $0.35
Diluted net income (loss) per limited partner unit$0.16
 $0.23
 $0.27
 $(0.31) $0.35
 Quarters Ended  
 March 31* June 30* September 30* December 31* Total Year*
2016:         
Revenues$6,447
 $7,866
 $8,156
 $9,323
 $31,792
Operating income680
 814
 624
 (275) 1,843
Net income (loss)320
 417
 (3) (734) —
Limited Partners’ interest in net income311
 239
 207
 226
 983
Basic net income per limited partner unit$0.30
 $0.23
 $0.20
 $0.22
 $0.94
Diluted net income per limited partner unit$0.30
 $0.23
 $0.19
 $0.21
 $0.92
* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.
The three months ended December 31, 20142017 and 2016 reflected the unfavorable impactsrecognition of $456 millionimpairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to non-cash inventory valuation adjustments primarily in ETP’s investment in Sunoco Logisticsinterstate transportation and retail marketingstorage operations, NGL and refined products operations and Regency’s recognition of a goodwill impairment of $370 million.other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 20132017 and December 31, 2016 reflected ETP’sthe recognition of a goodwillnon-cash impairment of $689 million.

F - 84
TableETP’s investments in subsidiaries of Contents$313 million and $308 million, respectively, in its interstate transportation and storage operations.


18.17.SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:
Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:
BALANCE SHEETS
 
December 31,December 31,
2014 20132017 2016
ASSETS      
CURRENT ASSETS:      
Cash and cash equivalents$2
 $8
$1
 $2
Accounts receivable from related companies14
 5
65
 55
Other current assets1
 —
1
 —
Total current assets17
 13
67
 57
PROPERTY, PLANT AND EQUIPMENT, net27
 36
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES5,390
 3,841
6,082
 5,088
INTANGIBLE ASSETS, net10
 14
—
 1
GOODWILL9
 9
9
 9
OTHER NON-CURRENT ASSETS, net46
 41
8
 10
Total assets$5,472
 $3,918
$6,193
 $5,201
LIABILITIES AND PARTNERS’ CAPITAL      
CURRENT LIABILITIES:      
Accounts payable$—
 $1
Accounts payable to related companies$11
 $11
—
 22
Interest payable58
 24
66
 66
Accrued and other current liabilities3
 3
4
 3
Total current liabilities72
 38
70
 92
LONG-TERM DEBT, less current maturities4,680
 2,801
6,700
 6,358
NOTE PAYABLE TO AFFILIATE54
 —
617
 443
OTHER NON-CURRENT LIABILITIES2
 1
2
 2
      
COMMITMENTS AND CONTINGENCIES
 

 
      
PARTNERS’ CAPITAL:   
PARTNERS’ DEFICIT:   
General Partner(1) (3)(3) (3)
Limited Partners:      
Limited Partners – Common Unitholders (538,766,899 and 559,923,300 units authorized, issued and outstanding at December 31, 2014 and 2013, respectively)648
 1,066
Class D Units (1,540,000 units authorized, issued and outstanding)22
 6
Accumulated other comprehensive income (loss)(5) 9
Total partners’ capital664
 1,078
Total liabilities and partners’ capital$5,472
 $3,918
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)(1,643) (1,871)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)450
 180
Total partners’ deficit(1,196) (1,694)
Total liabilities and partners’ deficit$6,193
 $5,201


F - 85

STATEMENTS OF OPERATIONS
 
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES$(111) $(56) $(53)$(31) $(185) $(112)
OTHER INCOME (EXPENSE):          
Interest expense, net of interest capitalized(205) (210) (235)(347) (327) (294)
Bridge loan related fees—
 —
 (62)
Equity in earnings of unconsolidated affiliates955
 617
 666
1,381
 1,511
 1,601
Gains (losses) on interest rate derivatives—
 9
 (15)
Loss on extinguishment of debt—
 (157) —
(47) —
 —
Other, net(5) (8) (4)(2) (4) (5)
INCOME BEFORE INCOME TAXES634
 195
 297
954
 995
 1,190
Income tax expense (benefit)1
 (1) (7)
Income tax expense—
 —
 1
NET INCOME633
 196
 304
954
 995
 1,189
GENERAL PARTNER’S INTEREST IN NET INCOME2
 —
 2
CLASS D UNITHOLDER’S INTEREST IN NET INCOME2
 —
 —
LIMITED PARTNERS’ INTEREST IN NET INCOME$629
 $196
 $302
General Partner’s interest in net income2
 3
 3
Convertible Unitholders’ interest in income37
 9
 —
Class D Unitholder’s interest in net income—
 —
 3
Limited Partners’ interest in net income$915
 $983
 $1,183


F - 86

STATEMENTS OF CASH FLOWS
 
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES$816
 $768
 $555
$831
 $918
 $1,103
CASH FLOWS FROM INVESTING ACTIVITIES:          
Cash paid for acquisitions—
 —
 (1,113)
Proceeds from ETP Holdco Transaction—
 1,332
 —
Cash paid for Bakken Pipeline Transaction—
 —
 (817)
Contributions to unconsolidated affiliates(118) (8) (487)(861) (70) —
Purchase of additional interest in Regency(800) —
 —
Note payable to affiliate54
 —
 —
Note receivable from affiliate—
 —
 (221)
Payments received on note receivable from affiliate—
 166
 55
Net cash provided by (used in) investing activities(864) 1,490
 (1,766)
Capital expenditures(1) (16) (19)
Contributions in aid of construction costs7
 —
 —
Net cash used in investing activities(855) (86) (836)
CASH FLOWS FROM FINANCING ACTIVITIES:          
Proceeds from borrowings3,020
 2,080
 2,108
2,219
 225
 3,672
Principal payments on debt(1,142) (3,235) (162)(1,881) (210) (1,985)
Distributions to partners(821) (733) (666)(1,010) (1,022) (1,090)
Redemption of Preferred Units—
 (340) —
Proceeds from affiliate174
 176
 210
Common Units issued for cash568
 —
 —
Units repurchased under buyback program(1,000) —
 —
—
 —
 (1,064)
Debt issuance costs(15) (31) (78)(47) —
 (11)
Net cash provided by (used in) financing activities42
 (2,259) 1,202
23
 (831) (268)
DECREASE IN CASH AND CASH EQUIVALENTS(6) (1) (9)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(1) 1
 (1)
CASH AND CASH EQUIVALENTS, beginning of period8
 9
 18
2
 1
 2
CASH AND CASH EQUIVALENTS, end of period$2
 $8
 $9
$1
 $2
 $1


F - 87

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS
OF CERTAIN SUBSIDIARIES INCLUDED PURSUANT
TO RULE 3-16 OF REGULATION S-X
 
 Page
1. Energy Transfer Partners, L.P. Financial StatementsS - 2
2. Regency Energy Partners LP Financial StatementsS - 75
  
  


S - 1

1.ENERGY TRANSFER PARTNERS, L.P. FINANCIAL STATEMENTS


INDEX TO FINANCIAL STATEMENTS
 
 Page
Report of Independent Registered Public Accounting Firm

S -6- 3
Consolidated Balance Sheets – December 31, 20142017 and 20132016S - 74
Consolidated Statements of Operations – Years Ended December 31, 2014, 20132017, 2016 and 20122015S - 96
Consolidated Statements of Comprehensive Income – Years Ended December 31, 2014, 20132017, 2016 and 20122015S - 107
Consolidated Statements of Equity – Years Ended December 31, 2014, 20132017, 2016 and 20122015S - 118
Consolidated Statements of Cash Flows – Years Ended December 31, 2014, 20132017, 2016 and 20122015S - 1210
Notes to Consolidated Financial StatementsS - 14
12



S - 2

Definitions
The following is a list of certain acronyms and terms generally used in the energy industry and throughout this document:
/dper day
AmeriGasAmeriGas Partners, L.P.
AOCIaccumulated other comprehensive income (loss)
AROsasset retirement obligations
Bblsbarrels
Bcfbillion cubic feet
BtuBritish thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used
Capacitycapacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may reduce the throughput capacity from specified capacity levels
CitrusCitrus, LLC
CrossCountryCrossCountry Energy, LLC
DOEU.S. Department of Energy
DOTU.S. Department of Transportation
EPAU.S. Environmental Protection Agency
ET Crude OilEnergy Transfer Crude Oil Company, LLC, a joint venture owned 60% by ETE and 40% by ETP
ETC CompressionETC Compression, LLC
ETC FEPETC Fayetteville Express Pipeline, LLC
ETC OLPLa Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company
ETC TigerETC Tiger Pipeline, LLC
ETEEnergy Transfer Equity, L.P., a publicly traded partnership and the owner of ETP LLC
ETE HoldingsETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
ET InterstateEnergy Transfer Interstate Holdings, LLC
ETP Credit FacilityETP’s $2.5 billion revolving credit facility
ETP GPEnergy Transfer Partners GP, L.P., the general partner of ETP
ETP Holdco
ETP Holdco Corporation

ETP LLCEnergy Transfer Partners, L.L.C., the general partner of ETP GP
Exchange ActSecurities Exchange Act of 1934
FEPFayetteville Express Pipeline LLC
FERCFederal Energy Regulatory Commission
FGTFlorida Gas Transmission Company, LLC
GAAPaccounting principles generally accepted in the United States of America
HOLPHeritage Operating, L.P.

S - 3

IDRsincentive distribution rights
Lake Charles LNGLake Charles LNG Company, LLC (previously named Trunkline LNG Company, LLC), a subsidiary of ETE
LCLLake Charles LNG Export Company, LLC, a subsidiary of ETP and ETE
LIBORLondon Interbank Offered Rate
LNGLiquefied natural gas
Lone StarLone Star NGL LLC
LPGliquefied petroleum gas
MACSMid-Atlantic Convenience Stores, LLC
MGEMissouri Gas Energy
MMBtumillion British thermal units
MMcfmillion cubic feet
MTBEmethyl tertiary butyl ether
NEGNew England Gas Company
NGLnatural gas liquid, such as propane, butane and natural gasoline
NYMEXNew York Mercantile Exchange
NYSENew York Stock Exchange
OSHAfederal Occupational Safety and Health Act
OTCover-the-counter
PanhandlePanhandle Eastern Pipe Line Company, LP and its subsidiaries
PCBspolychlorinated biphenyls
PEPL HoldingsPEPL Holdings, LLC
PESPhiladelphia Energy Solutions
PHMSAPipeline Hazardous Materials Safety Administration
RegencyRegency Energy Partners LP, a subsidiary of ETE
Retail HoldingsETP Retail Holdings, a joint venture between subsidiaries of ETC OLP and Sunoco, Inc.
Sea RobinSea Robin Pipeline Company, LLC, a subsidiary of Panhandle
SECSecurities and Exchange Commission
Southern UnionSouthern Union Company
Southwest GasPan Gas Storage, LLC (d.b.a. Southwest Gas)
SUGSSouthern Union Gas Services

S - 4

Sunoco LogisticsSunoco Logistics Partners L.P.
Sunoco PartnersSunoco Partners LLC, the general partner of Sunoco Logistics
SusserSusser Holdings Corporation
TitanTitan Energy Partners, L.P.
TranswesternTranswestern Pipeline Company, LLC
TRRCTexas Railroad Commission
TrunklineTrunkline Gas Company, LLC, a subsidiary of Panhandle
Adjusted EBITDA is a term used throughout this document, which we define as earnings before interest, taxes, depreciation, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Adjusted EBITDA reflects amounts for less than wholly-owned subsidiaries based on 100% of the subsidiaries’ results of operations and for unconsolidated affiliates based on the Partnership’s proportionate ownership.


S - 5


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Partners

Board of Directors of Energy Transfer Partners, L.L.C. and
Unitholders of Energy Transfer Partners, L.P.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 20142017 and 2013, and2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are2017, and the responsibility ofrelated notes (collectively referred to as the Partnership’s management. Our responsibility is to express an“financial statements”). In our opinion, on these financial statements based on our audits. We did not audit the financial statements of Sunoco LP and Susser Holdings Corporation, both consolidated subsidiaries, as of December 31, 2014 and for the period from September 1, 2014 to December 31, 2014, whose combined statements reflect total assets constituting 11 percent of consolidated total assets as of December 31, 2014, and total revenues of 5 percent of consolidated total revenues for the year then ended. Those statements were audited by other auditors, whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco LP and Susser Holdings Corporation, is based solely on the reports of the other auditors. We did not audit the financial statements of Sunoco Logistics Partners L.P., a consolidated subsidiary, for the period from October 5, 2012 to December 31, 2012, which statements reflect revenues of 20 percent of consolidated total revenues for the year ended December 31, 2012. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Sunoco Logistics Partners L.P. for the period from October 5, 2012 to December 31, 2012, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Partners, L.P. and subsidiariesthe Partnership as of December 31, 20142017 and 2013,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20142017, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2014,2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”), and our report dated March 2, 2015 (notFebruary 23, 2018 (not separately included herein) expressed an unqualified opinion thereon.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2004.

Dallas, Texas
March 2, 2015February 23, 2018

S - 6

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2014 2013
ASSETS   
CURRENT ASSETS:   
Cash and cash equivalents$639
 $549
Accounts receivable, net2,879
 3,359
Accounts receivable from related companies210
 165
Inventories1,389
 1,765
Exchanges receivable44
 56
Price risk management assets7
 35
Other current assets271
 310
Total current assets5,439
 6,239
    
PROPERTY, PLANT AND EQUIPMENT33,200
 28,430
ACCUMULATED DEPRECIATION(3,457) (2,483)
 29,743
 25,947
    
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES3,840
 4,436
NON-CURRENT PRICE RISK MANAGEMENT ASSETS—
 17
GOODWILL6,419
 4,729
INTANGIBLE ASSETS, net2,087
 1,568
OTHER NON-CURRENT ASSETS, net693
 766
Total assets$48,221
 $43,702
 December 31,
 2017 2016*
ASSETS   
Current assets:   
Cash and cash equivalents$306
 $360
Accounts receivable, net3,946
 3,002
Accounts receivable from related companies318
 209
Inventories1,589
 1,626
Income taxes receivable135
 128
Derivative assets24
 20
Other current assets210
 298
Total current assets6,528
 5,643
    
Property, plant and equipment67,699
 58,220
Accumulated depreciation and depletion(9,262) (7,303)
 58,437
 50,917
    
Advances to and investments in unconsolidated affiliates3,816
 4,280
Other non-current assets, net758
 672
Intangible assets, net5,311
 4,696
Goodwill3,115
 3,897
Total assets$77,965
 $70,105
* As adjusted. See Note 2.

S - 7

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2014 2013
LIABILITIES AND EQUITY   
CURRENT LIABILITIES:   
Accounts payable$2,992
 $3,627
Accounts payable to related companies62
 45
Exchanges payable183
 285
Price risk management liabilities21
 45
Accrued and other current liabilities1,774
 1,428
Current maturities of long-term debt1,008
 637
Total current liabilities6,040
 6,067
    
LONG-TERM DEBT, less current maturities18,332
 16,451
NON-CURRENT PRICE RISK MANAGEMENT LIABILITIES138
 54
DEFERRED INCOME TAXES4,226
 3,762
OTHER NON-CURRENT LIABILITIES1,206
 1,080
    
COMMITMENTS AND CONTINGENCIES (Note 11)   
REDEEMABLE NONCONTROLLING INTERESTS15
 —
    
EQUITY:   
General Partner184
 171
Limited Partners:   
Common Unitholders (355,510,227 and 333,826,372 units authorized, issued and outstanding as of December 31, 2014 and 2013, respectively)10,430
 9,797
Class E Unitholders (8,853,832 units authorized, issued and outstanding – held by subsidiary)—
 —
Class G Unitholders (90,706,000 units authorized, issued and outstanding – held by subsidiary)—
 —
Class H Unitholders (50,160,000 units authorized, issued and outstanding)1,512
 1,511
Accumulated other comprehensive income (loss)(56) 61
Total partners’ capital12,070
 11,540
Noncontrolling interest6,194
 4,748
Total equity18,264
 16,288
Total liabilities and equity$48,221
 $43,702
 December 31,
 2017 2016*
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable$4,126
 $2,900
Accounts payable to related companies209
 43
Derivative liabilities109
 166
Accrued and other current liabilities2,143
 1,905
Current maturities of long-term debt407
 1,189
Total current liabilities6,994
 6,203
    
Long-term debt, less current maturities32,687
 31,741
Long-term notes payable – related company—
 250
Non-current derivative liabilities145
 76
Deferred income taxes2,883
 4,394
Other non-current liabilities1,084
 952
    
Commitments and contingencies
 

Legacy ETP Preferred Units—
 33
Redeemable noncontrolling interests21
 15
    
Equity:   
Series A Preferred Units (950,000 units authorized, issued and outstanding as of December 31, 2017)944
 —
Series B Preferred Units (550,000 units authorized, issued and outstanding as of December 31, 2017)547
 —
Limited Partners:   
Common Unitholders (1,164,112,575 and 794,803,854 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)26,531
 14,925
Class E Unitholder (8,853,832 units authorized, issued and outstanding – held by subsidiary)—
 —
Class G Unitholder (90,706,000 units authorized, issued and outstanding – held by subsidiary)—
 —
Class H Unitholder (81,001,069 units authorized, issued and outstanding as of December 31, 2016)—
 3,480
Class I Unitholder (100 units authorized, issued and outstanding)—
 2
Class K Unitholders (101,525,429 units authorized, issued and outstanding – held by subsidiaries)—
 —
General Partner244
 206
Accumulated other comprehensive income3
 8
Total partners’ capital28,269
 18,621
Noncontrolling interest5,882
 7,820
Total equity34,151
 26,441
Total liabilities and equity$77,965
 $70,105
* As adjusted. See Note 2.

S - 8

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
 Years Ended December 31,
 2014 2013 2012
REVENUES:     
Natural gas sales$3,561
 $3,165
 $2,387
NGL sales4,293
 2,817
 1,718
Crude sales16,416
 15,477
 2,872
Gathering, transportation and other fees2,553
 2,590
 2,007
Refined product sales19,437
 18,479
 5,299
Other4,898
 3,811
 1,419
Total revenues51,158
 46,339
 15,702
COSTS AND EXPENSES:     
Cost of products sold45,540
 41,204
 12,266
Operating expenses1,636
 1,441
 953
Depreciation and amortization1,130
 1,032
 656
Selling, general and administrative377
 432
 433
Goodwill impairment—
 689
 —
Total costs and expenses48,683
 44,798
 14,308
OPERATING INCOME2,475
 1,541
 1,394
OTHER INCOME (EXPENSE):     
Interest expense, net of interest capitalized(860) (849) (665)
Equity in earnings of unconsolidated affiliates234
 172
 142
Gain on deconsolidation of Propane Business—
 —
 1,057
Gain on sale of AmeriGas common units177
 87
 —
Loss on extinguishment of debt—
 —
 (115)
Gains (losses) on interest rate derivatives(157) 44
 (4)
Non-operating environmental remediation—
 (168) —
Other, net(25) 5
 11
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE1,844
 832
 1,820
Income tax expense from continuing operations355
 97
 63
INCOME FROM CONTINUING OPERATIONS1,489
 735
 1,757
Income (loss) from discontinued operations64
 33
 (109)
NET INCOME1,553
 768
 1,648
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST217
 312
 79
NET INCOME ATTRIBUTABLE TO PARTNERS1,336
 456
 1,569
GENERAL PARTNER’S INTEREST IN NET INCOME513
 506
 461
CLASS H UNITHOLDER’S INTEREST IN NET INCOME217
 48
 —
COMMON UNITHOLDERS’ INTEREST IN NET INCOME (LOSS)$606
 $(98) $1,108
INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT:     
Basic$1.58
 $(0.23) $4.93
Diluted$1.58
 $(0.23) $4.91
NET INCOME (LOSS) PER COMMON UNIT:     
Basic$1.77
 $(0.18) $4.43
Diluted$1.77
 $(0.18) $4.42
 Years Ended December 31,
 2017 2016* 2015*
REVENUES:     
Natural gas sales$4,172
 $3,619
 $3,671
NGL sales6,972
 4,841
 3,936
Crude sales10,184
 6,766
 8,378
Gathering, transportation and other fees4,265
 4,003
 3,997
Refined product sales (see Note 3)1,515
 1,047
 9,958
Other (see Note 3)1,946
 1,551
 4,352
Total revenues29,054
 21,827
 34,292
COSTS AND EXPENSES:     
Cost of products sold (see Note 3)20,801
 15,080
 26,714
Operating expenses (see Note 3)2,170
 1,839
 2,608
Depreciation, depletion and amortization2,332
 1,986
 1,929
Selling, general and administrative (see Note 3)434
 348
 475
Impairment losses920
 813
 339
Total costs and expenses26,657
 20,066
 32,065
OPERATING INCOME2,397
 1,761
 2,227
OTHER INCOME (EXPENSE):     
Interest expense, net(1,365) (1,317) (1,291)
Equity in earnings from unconsolidated affiliates156
 59
 469
Impairment of investments in unconsolidated affiliates(313) (308) —
Gains on acquisitions—
 83
 —
Losses on extinguishments of debt(42) —
 (43)
Losses on interest rate derivatives(37) (12) (18)
Other, net209
 131
 22
INCOME BEFORE INCOME TAX BENEFIT1,005
 397
 1,366
Income tax benefit(1,496) (186) (123)
NET INCOME2,501
 583
 1,489
Less: Net income attributable to noncontrolling interest420
 295
 134
Less: Net loss attributable to predecessor—
 —
 (34)
NET INCOME ATTRIBUTABLE TO PARTNERS2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)$986
 $(1,019) $(27)
NET INCOME (LOSS) PER COMMON UNIT:     
Basic$0.94
 $(1.38) $(0.07)
Diluted$0.93
 $(1.38) $(0.08)
* As adjusted. See Note 2.

S - 9

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016* 2015*
Net income$1,553
 $768
 $1,648
$2,501
 $583
 $1,489
Other comprehensive income (loss), net of tax:          
Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges3
 (4) (14)
Change in value of derivative instruments accounted for as cash flow hedges—
 (1) 8
Change in value of available-for-sale securities1
 2
 —
6
 2
 (3)
Actuarial gain (loss) relating to pension and other postretirement benefits(113) 66
 (10)(12) (1) 65
Foreign currency translation adjustment(2) (1) —
—
 (1) (1)
Change in other comprehensive income from unconsolidated affiliates(6) 17
 (9)
Change in other comprehensive income (loss) from unconsolidated affiliates1
 4
 (1)
(117) 79
 (25)(5) 4
 60
Comprehensive income1,436
 847
 1,623
2,496
 587
 1,549
Less: Comprehensive income attributable to noncontrolling interest217
 312
 74
420
 295
 134
Less: Comprehensive loss attributable to predecessor—
 —
 (34)
Comprehensive income attributable to partners$1,219
 $535
 $1,549
$2,076
 $292
 $1,449
* As adjusted. See Note 2.

S - 10

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
  Limited Partners          Limited Partners          
General
Partner
 
Common
Unitholders
 Class H Units 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interest
 TotalSeries A Preferred Units Series B Preferred Units Common Unit holders Class H Units Class I Units General
Partner		 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-controlling
Interest
 Predecessor Equity Total
Balance, December 31, 2011$182
 $5,533
 $—
 $6
 $629
 $6,350
Distributions to partners(454) (889) —
 —
 —
 (1,343)
Distributions to noncontrolling interest—
 —
 —
 —
 (233) (233)
Units issued for cash—
 791
 —
 —
 —
 791
Capital contributions from noncontrolling interest—
 —
 —
 —
 343
 343
Sunoco Merger (see Note 3)—
 2,288
 —
 —
 3,580
 5,868
ETP Holdco Transaction (see Note 3)—
 165
 —
 —
 3,748
 3,913
Issuance of units in other acquisitions (excluding Sunoco, Inc.)—
 7
 —
 —
 —
 7
Other comprehensive loss, net of tax—
 —
 —
 (19) (6) (25)
Other, net(1) 23
 —
 —
 (9) 13
Net income461
 1,108
 —
 —
 79
 1,648
Balance, December 31, 2012188
 9,026
 —
 (13) 8,131
 17,332
Distributions to partners(523) (1,228) (51) —
 —
 (1,802)
Distributions to noncontrolling interest—
 —
 —
 —
 (382) (382)
Units issued for cash—
 1,611
 —
 —
 —
 1,611
Issuance of Class H Units (see Note 8)—
 (1,514) 1,514
 —
 —
 —
Capital contributions from noncontrolling interest—
 —
 —
 —
 137
 137
ETP Holdco Acquisition and SUGS Contribution (see Note 3)—
 2,013
 —
 (5) (3,448) (1,440)
Other comprehensive income, net of tax—
 —
 —
 79
 —
 79
Other, net—
 (13) —
 —
 (2) (15)
Net income (loss)506
 (98) 48
 —
 312
 768
Balance, December 31, 2013171
 9,797
 1,511
 61
 4,748
 16,288
Balance, December 31, 2014*$—
 $—
 $10,427
 $1,512
 $—
 $184
 $(56) $5,143
 $8,088
 $25,298
Distributions to partners(500) (1,252) (212) —
 —
 (1,964)—
 —
 (1,863) (247) (80) (944) —
 —
 —
 (3,134)
Distributions to noncontrolling interest—
 —
 —
 —
 (362) (362)—
 —
 —
 —
 —
 —
 —
 (338) —
 (338)
Units issued for cash—
 1,382
 —
 —
 —
 1,382
—
 —
 1,428
 —
 —
 —
 —
 —
 —
 1,428
Subsidiary units issued for cash1
 174
 —
 —
 1,069
 1,244
—
 —
 298
 —
 —
 2
 —
 1,219
 —
 1,519
Capital contributions from noncontrolling interest—
 —
 —
 —
 161
 161
—
 —
 —
 —
 —
 —
 —
 875
 —
 875
Lake Charles LNG Transaction (see Note 3)—
 (1,167) —
 —
 —
 (1,167)
Susser Merger (see Note 3)—
 908
 —
 —
 626
 1,534
Sunoco Logistics acquisition of a noncontrolling interest(1) (79) —
 —
 (245) (325)
Other comprehensive loss, net of tax—
 —
 —
 (117) —
 (117)
Bakken Pipeline Transaction—
 —
 (999) 1,946
 —
 —
 —
 72
 —
 1,019
Sunoco LP Exchange Transaction—
 —
 (52) —
 —
 —
 —
 (940) —
 (992)
Susser Exchange Transaction—
 —
 (68) —
 —
 —
 —
 —
 —
 (68)
Acquisition and disposition of noncontrolling interest—
 —
 (26) —
 —
 —
 —
 (39) —
 (65)
Predecessor distributions to partners—
 —
 —
 —
 —
 —
 —
 —
 (202) (202)
Predecessor units issued for cash—
 —
 —
 —
 —
 —
 —
 —
 34
 34
Regency Merger—
 —
 7,890
 —
 —
 —
 —
 —
 (7,890) —
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 60
 —
 —
 60
Other, net—
 61
 (4) —
 (20) 37
—
 —
 23
 —
 —
 —
 —
 36
 4
 63
Net income513
 606
 217
 —
 217
 1,553
Balance, December 31, 2014$184
 $10,430
 $1,512
 $(56) $6,194
 $18,264
Net income (loss)—
 —
 (27) 258
 94
 1,064
 —
 134
 (34) 1,489
Balance, December 31, 2015*—
 —
 17,031
 3,469
 14
 306
 4
 6,162
 —
 26,986
Distributions to partners—
 —
 (2,134) (340) (20) (1,048) —
 —
 —
 (3,542)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (481) —
 (481)
Units issued for cash—
 —
 1,098
 —
 —
 —
 —
 —
 —
 1,098
Subsidiary units issued—
 —
 37
 —
 —
 —
 —
 1,351
 —
 1,388

S - 11
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 236
 —
 236
Sunoco, Inc. retail business to Sunoco LP transaction—
 —
 (405) —
 —
 —
 —
 —
 —
 (405)
PennTex Acquisition—
 —
 307
 —
 —
 —
 —
 236
 —
 543
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 4
 —
 —
 4
Other, net—
 —
 10
 —
 —
 —
 —
 21
 —
 31
Net income (loss)—
 —
 (1,019) 351
 8
 948
 —
 295
 —
 583
Balance, December 31, 2016*—
 —
 14,925
 3,480
 2
 206
 8
 7,820
 —
 26,441
Distributions to partners—
 —
 (2,419) (95) (2) (952) —
 —
 —
 (3,468)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (430) —
 (430)
Units issued for cash937
 542
 2,283
 —
 —
 —
 —
 —
 —
 3,762
Sunoco Logistics Merger—
 —
 9,416
 (3,478) —
 —
 —
 (5,938) —
 —
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 2,202
 —
 2,202
Sale of Bakken Pipeline interest—
 —
 1,260
 —
 —
 —
 —
 740
 —
 2,000
Sale of Rover Pipeline interest—
 —
 93
 —
 —
 —
 —
 1,385
 —
 1,478
Acquisition of PennTex noncontrolling interest—
 —
 (48) —
 —
 —
 —
 (232) —
 (280)
Other comprehensive loss, net of tax—
 —
 —
 —
 —
 —
 (5) —
 —
 (5)
Other, net—
 —
 35
 —
 —
 —
 —
 (85) —
 (50)
Net income7
 5
 986
 93
 —
 990
 —
 420
 —
 2,501
Balance, December 31, 2017$944
 $547
 $26,531
 $—
 $—
 $244
 $3
 $5,882
 $—
 $34,151
Table of Contents* As adjusted. See Note 2.


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Years Ended December 31,
 2014 2013 2012
CASH FLOWS FROM OPERATING ACTIVITIES:     
Net income$1,553
 $768
 $1,648
Reconciliation of net income to net cash provided by operating activities:     
Depreciation and amortization1,130
 1,032
 656
Deferred income taxes(47) 48
 62
Amortization included in interest expense(61) (80) (35)
Inventory valuation adjustments473
 (3) 75
Non-cash compensation expense58
 47
 42
Goodwill impairment—
 689
 —
Gain on sale of AmeriGas common units(177) (87) —
Gain on deconsolidation of Propane Business—
 —
 (1,057)
Gain on curtailment of other postretirement benefits—
 —
 (15)
Loss on extinguishment of debt—
 —
 115
Write-down of assets included in loss from discontinued operations—
 —
 132
Distributions on unvested awards(16) (12) (8)
Equity in earnings of unconsolidated affiliates(234) (172) (142)
Distributions from unconsolidated affiliates203
 247
 132
Other non-cash(60) 42
 68
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations (see Note 2)(264) (146) (475)
Net cash provided by operating activities2,558
 2,373
 1,198
CASH FLOWS FROM INVESTING ACTIVITIES:     
Cash paid for Susser Merger, net of cash received (see Note 3)(808) —
 —
Cash paid for acquisition of a noncontrolling interest(325) —
 —
Cash paid for ETP Holdco Acquisition (See Note 3)—
 (1,332) —
Cash paid for Citrus Merger—
 —
 (1,895)
Cash proceeds from the sale of AmeriGas common units814
 346
 —
Cash proceeds from SUGS Contribution (See Note 3)—
 504
 —
Cash proceeds from contribution and sale of propane operations—
 —
 1,443
Cash (paid) received from all other acquisitions(429) (405) 531
Capital expenditures (excluding allowance for equity funds used during construction)(4,158) (2,575) (2,840)
Contributions in aid of construction costs45
 52
 35
Contributions to unconsolidated affiliates(170) (1) (30)
Distributions from unconsolidated affiliates in excess of cumulative earnings151
 217
 130
Proceeds from sale of discontinued operations77
 1,008
 207
Proceeds from the sale of assets50
 53
 18
Change in restricted cash172
 (348) 5
Other(17) 21
 111
Net cash used in investing activities(4,598) (2,460) (2,285)
      
 Years Ended December 31,
 2017 2016* 2015*
OPERATING ACTIVITIES:     
Net income$2,501
 $583
 $1,489
Reconciliation of net income to net cash provided by operating activities:     
Depreciation, depletion and amortization2,332
 1,986
 1,929
Deferred income taxes(1,531) (169) 202
Amortization included in interest expense2
 (20) (36)
Inventory valuation adjustments—
 —
 (58)
Unit-based compensation expense74
 80
 79
Impairment losses920
 813
 339
Gains on acquisitions—
 (83) —
Losses on extinguishments of debt42
 —
 43
Impairment of investments in unconsolidated affiliates313
 308
 —
Distributions on unvested awards(31) (25) (16)
Equity in earnings of unconsolidated affiliates(156) (59) (469)
Distributions from unconsolidated affiliates440
 406
 440
Other non-cash(261) (271) (22)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations(160) (246) (1,173)
Net cash provided by operating activities4,485
 3,303
 2,747
INVESTING ACTIVITIES:     
Cash proceeds from sale of Bakken Pipeline interest2,000
 —
 —
Cash proceeds from sale of Rover Pipeline interest1,478
 —
 —
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction—
 2,200
 —
Proceeds from Bakken Pipeline Transaction—
 —
 980
Proceeds from Susser Exchange Transaction—
 —
 967
Proceeds from sale of noncontrolling interest—
 —
 64
Cash paid for acquisition of PennTex noncontrolling interest(280) —
 —
Cash paid for Vitol Acquisition, net of cash received—
 (769) —
Cash paid for PennTex Acquisition, net of cash received—
 (299) —
Cash transferred to ETE in connection with the Sunoco LP Exchange—
 —
 (114)
Cash paid for acquisition of a noncontrolling interest—
 —
 (129)
Cash paid for all other acquisitions(264) (159) (675)
Capital expenditures, excluding allowance for equity funds used during construction(8,335) (7,550) (9,098)
Contributions in aid of construction costs24
 71
 80
Contributions to unconsolidated affiliates(268) (59) (45)
Distributions from unconsolidated affiliates in excess of cumulative earnings136
 135
 124
Proceeds from the sale of assets35
 25
 23
Change in restricted cash—
 14
 19
Other1
 1
 (16)
Net cash used in investing activities(5,473) (6,390) (7,820)
      

S - 12

CASH FLOWS FROM FINANCING ACTIVITIES:     
Proceeds from borrowings9,909
 8,001
 8,208
Repayments of long-term debt(8,223) (7,016) (6,598)
Proceeds from borrowings from affiliates—
 —
 221
Repayments of borrowings from affiliates—
 (166) (55)
Net proceeds from issuance of Common Units1,382
 1,611
 791
Subsidiary equity offerings, net of issuance costs1,244
 —
 —
Capital contributions received from noncontrolling interest174
 147
 320
Distributions to partners(1,964) (1,802) (1,343)
Distributions to noncontrolling interest(362) (382) (233)
Debt issuance costs(30) (32) (20)
Other—
 (36) —
Net cash provided by financing activities2,130
 325
 1,291
INCREASE IN CASH AND CASH EQUIVALENTS90
 238
 204
CASH AND CASH EQUIVALENTS, beginning of period549
 311
 107
CASH AND CASH EQUIVALENTS, end of period$639
 $549
 $311
FINANCING ACTIVITIES:     
Proceeds from borrowings26,736
 19,916
 22,462
Repayments of long-term debt(26,494) (15,799) (17,843)
Cash (paid to) received from affiliate notes(255) 124
 233
Common Units issued for cash2,283
 1,098
 1,428
Preferred Units issued for cash1,479
 —
 —
Subsidiary units issued for cash—
 1,388
 1,519
Predecessor units issued for cash—
 —
 34
Capital contributions from noncontrolling interest1,214
 236
 841
Distributions to partners(3,468) (3,542) (3,134)
Predecessor distributions to partners—
 —
 (202)
Distributions to noncontrolling interest(430) (481) (338)
Redemption of Legacy ETP Preferred Units(53) —
 —
Debt issuance costs(83) (22) (63)
Other5
 2
 —
Net cash provided by financing activities934
 2,920
 4,937
Decrease in cash and cash equivalents(54) (167) (136)
Cash and cash equivalents, beginning of period360
 527
 663
Cash and cash equivalents, end of period$306
 $360
 $527
* As adjusted. See Note 2.


S - 13


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)

1.OPERATIONS AND ORGANIZATION:BASIS OF PRESENTATION:
Organization. The consolidated financial statements and notes theretopresented herein contain the results of Energy Transfer Partners, L.P., and its subsidiaries (the “Partnership,” “we”“we,” “us,” “our” or “ETP”) presented herein. The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner.
In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled.
In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein:
References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;
References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and
References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.
The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the years endedpre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes).
The Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales.
The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.
The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.

The Partnership owns a controlling interest in Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
Basis of Presentation. December 31, 2014, 2013 and 2012,The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and pursuantinclude the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and subsidiaries we control, even if we do not have a majority ownership. All significant intercompany transactions and accounts are eliminated in consolidation.current year presentation. These reclassifications had no impact on net income or total equity. Management has evaluated subsequent events through the date the financial statements were issued.
We also ownFor prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.
The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for ourthese undivided interests in these assets.
Certain prior period amounts have been reclassified to conform to the 2014 presentation. These reclassifications had no impact on net income or total equity.
We are managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner. The consolidated financial statements of the Partnership presented herein include our operating subsidiaries described below.
Our consolidated subsidiary, Susser Petroleum Partners LP, changed its name in October 2014 to Sunoco LP. Additionally, Trunkline LNG Company, LLC, a consolidated subsidiary of ETE, changed its name in September 2014 to Lake Charles LNG Company, LLC. All references to these entities throughout this document reflect the new name of these entities, regardless of whether the disclosure relates to periods or events prior to the dates of the name changes.
Business Operations
Our activities are primarily conducted through our operating subsidiaries (collectively, the “Operating Companies”) as follows:
ETC OLP, a Texas limited partnership primarily engaged in midstream and intrastate transportation and storage natural gas operations. ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. ETC OLP’s intrastate transportation and storage operations primarily focus on transporting natural gas in Texas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System. ETC OLP’s midstream operations focus on the gathering, compression, treating, conditioning and processing of natural gas, primarily on or through our Southeast Texas System, Eagle Ford System, North Texas System and Northern Louisiana assets. ETC OLP also owns a 70% interest in Lone Star.
ET Interstate, a Delaware limited liability company with revenues consisting primarily of fees earned from natural gas transportation services and operational gas sales. ET Interstate is the parent company of:
Transwestern, a Delaware limited liability company engaged in interstate transportation of natural gas. Transwestern’s revenues consist primarily of fees earned from natural gas transportation services and operational gas sales.
ETC FEP, a Delaware limited liability company that directly owns a 50% interest in FEP, which owns 100% of the Fayetteville Express interstate natural gas pipeline.
ETC Tiger, a Delaware limited liability company engaged in interstate transportation of natural gas.
CrossCountry, a Delaware limited liability company that indirectly owns a 50% interest in Citrus, which owns 100% of the FGT interstate natural gas pipeline.
ETC Compression, a Delaware limited liability company engaged in natural gas compression services and related equipment sales.

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ETP Holdco, a Delaware limited liability company that indirectly owns Panhandle and Sunoco, Inc. Panhandle and Sunoco, Inc. operations are described as follows:
Panhandle owns and operates assets in the regulated and unregulated natural gas industry and is primarily engaged in the transportation and storage of natural gas in the United States. As discussed in Note 3, in January 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle, and PEPL Holdings, the sole limited partner of Panhandle, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle, with Panhandle surviving the merger.
Sunoco, Inc. owns and operates retail marketing assets, which sell gasoline and middle distillates at retail locations and operates convenience stores primarily on the east coast and in the midwest region of the United States. Effective June 1, 2014, the Partnership combined certain Sunoco, Inc. retail assets with another wholly-owned subsidiary of ETP to form a limited liability company owned by ETP and Sunoco, Inc.
Sunoco Logistics, a publicly traded Delaware limited partnership that owns and operates a logistics business, consisting of products, crude oil and NGL pipelines, terminalling and storage assets, and refined products, crude oil and NGL acquisition and marketing assets.
ETP owns an indirect 100% equity interest in Susser and the general partner interest, incentive distribution rights and a 42.8% limited partner interest in Sunoco LP. Susser operates convenience stores in Texas, New Mexico and Oklahoma. Sunoco LP distributes motor fuels to convenience stores and retail fuel outlets in Texas, New Mexico, Oklahoma, Kansas and Louisiana and other commercial customers. As discussed in Note 3, in October 2014, Sunoco LP acquired MACS from ETP. These operations are reported within the retail marketing segment.
Our financial statements reflect the following reportable business segments:
intrastate transportation and storage;
interstate transportation and storage;
midstream;
liquids transportation and services;
investment in Sunoco Logistics;
retail marketing; and
all other.proportionately.
2.ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Change in Accounting Policy
During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows:
 Year Ended December 31, 2016 Year Ended December 31, 2015
 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted
Consolidated Statement of Operations and Comprehensive Income:           
Cost of products sold$15,039
 $41
 $15,080
 $26,682
 $32
 $26,714
Operating income1,802
 (41) 1,761
 2,259
 (32) 2,227
Income before income tax benefit438
 (41) 397
 1,398
 (32) 1,366
Net income624
 (41) 583
 1,521
 (32) 1,489
Net income attributable to partners297
 (9) 288
 1,398
 (9) 1,389
Net loss per common unit - basic(1.37) (0.01) (1.38) (0.06) (0.01) (0.07)
Net loss per common unit - diluted(1.37) (0.01) (1.38) (0.07) (0.01) (0.08)
Comprehensive income628
 (41) 587
 1,581
 (32) 1,549
Comprehensive income attributable to partners301
 (9) 292
 1,458
 (9) 1,449
            
Consolidated Statements of Cash Flows:           
Net income624
 (41) 583
 1,521
 (32) 1,489
Net change in operating assets and liabilities (change in inventories)(117) (129) (246) (1,367) 194
 (1,173)
            
Consolidated Balance Sheets (at period end):           
Inventories1,712
 (86) 1,626
 1,213
 (45) 1,168
Total partners' capital18,642
 (21) 18,621
 20,836
 (12) 20,824
* Amounts reflect certain reclassifications made to conform to the current year presentation.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
NewRecent Accounting Pronouncements
ASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“(“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

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TableThe Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of Contentsthe retrospective application of the standard. The effect of the retrospective application of the standard was not material.
For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of our midstream segment agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.

ASU 2014-092016-02
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-16
On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.
ASU 2017-12
In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for annual reportingfinancial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, including interim periods within that reporting period,2018, with earlierearly adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact if any, that adopting this new accounting standard will have on our revenue recognition policies.
In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements (Topic 205)consolidated financial statements and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”), which changed the requirements for reporting discontinued operations.  Under ASU 2014-08, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results.  ASU 2014-08 is effective for all disposals or classifications as held for sale of components of an entity that occur within fiscal years beginning after December 15, 2014, and early adoption is permitted. We expect to adopt this standard for the year ending December 31, 2015. ASU 2014-08 could have an impact on whether transactions will be reported in discontinued operations in the future, as well as the disclosures required when a component of an entity is disposed.related disclosures.
Revenue Recognition
Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation.sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the

pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.
In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and grosssegment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services

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under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third partythird-party pipeline, which is when title and risk of loss pass to the customer.
In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
Our retail marketing segment sells gasoline and diesel in addition to a broad mix of merchandise such as groceries, fast foods and beverages at its convenience stores. A portion of our gasoline and diesel sales are to wholesale customers on a consignment basis, in which we retain title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. We typically own the fuel dispensing equipment and underground storage tanks at consignment sites, and in some cases we own the entire site and have entered into an operating lease with the wholesale customer operating the site. In addition, our retail outlets derive other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rental and other ancillary product and service offerings. Some of Sunoco, Inc.’s retail outlets provide a variety of car care services. Revenues related to the sale of products are recognized when title passes, while service revenues are recorded on a net commission basis and are recognized when services are provided. Title passage generally occurs when products are shipped or delivered in accordance with the terms of the respective sales agreements. In addition, revenues are not recognized until sales prices are fixed or determinable and collectability is reasonably assured.
Regulatory Accounting – Regulatory Assets and Liabilities
Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  In 1999, prior to its acquisition by Southern Union, Panhandle discontinued the application ofdoes not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.

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Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities (net of acquisitions)effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:
Years Ended December 31,Years Ended December 31,
2014 2013 20122017 2016 2015
Accounts receivable$547
 $(458) $300
$(950) $(919) $819
Accounts receivable from related companies(45) (17) (50)67
 30
 (243)
Inventories79
 (256) (253)37
 (497) (157)
Exchanges receivable6
 (24) 11
Other current assets120
 (56) 571
39
 83
 (178)
Other non-current assets, net(6) (22) (53)(94) (78) 188
Accounts payable(804) 525
 (979)758
 972
 (1,215)
Accounts payable to related companies20
 (122) 100
(3) 29
 (160)
Exchanges payable(100) 131
 —
Accrued and other current liabilities(118) 152
 (151)(47) 39
 (83)
Other non-current liabilities(75) 151
 25
24
 33
 (219)
Price risk management assets and liabilities, net112
 (150) 4
9
 62
 75
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations$(264) $(146) $(475)$(160) $(246) $(1,173)

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Non-cash investing and financing activities and supplemental cash flow information are as follows:
 Years Ended December 31,
 2014 2013 2012
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$541
 $167
 $359
Net gains from subsidiary common unit issuances$175
 $—
 $—
Regency common and Class F units received in exchange for contribution of SUGS$—
 $961
 $—
AmeriGas limited partner interest received in exchange for contribution of Propane Business$—
 $—
 $1,123
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with the Susser Merger (see Note 3)$908
 $—
 $—
Redemption of Common Units in connection with the Lake Charles LNG Transaction (see Note 3)$1,167
 $—
 $—
Issuance of Common Units in connection with the ETP Holdco Acquisition$—
 $2,464
 $—
Issuance of Class H Units$—
 $1,514
 $—
Issuance of Common Units in connection with other acquisitions$—
 $—
 $2,295
Contributions receivable related to noncontrolling interest$—
 $13
 $23
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$929
 $903
 $678
Cash paid for income taxes$343
 $57
 $22
 Years Ended December 31,
 2017 2016 2015
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$1,059
 $822
 $896
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP—
 194
 —
Net gains from subsidiary common unit transactions—
 37
 300
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with the PennTex Acquisition$—
 $307
 $—
Issuance of Common Units in connection with the Regency Merger—
 —
 9,250
Issuance of Class H Units in connection with the Bakken Pipeline Transaction—
 —
 1,946
Contribution of assets from noncontrolling interest988
 —
 34
Redemption of Common Units in connection with the Bakken Pipeline Transaction—
 —
 999
Redemption of Common Units in connection with the Sunoco LP Exchange—
 —
 52
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$1,329
 $1,411
 $1,467
Cash paid for (refund of) income taxes50
 (229) 71
Accounts Receivable
Our midstream, NGL and intrastate transportation and storage operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned forto all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. Master setoff agreements
We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are putengaged in place with counterparties where appropriatethe exploration and production segment. We manage trade credit risk to mitigate risk. Bad debt expense relatedcredit losses and exposure to these receivables is recognized atuncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the time an account is deemed uncollectible.
Our investment in Sunoco Logistics segment extends credit terms to certain customers after reviewform of various credit indicators, including the customer’s credit rating. Based on that review, a letter of credit, or other security may be required. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted.
Our interstate transportation and storage operations have a concentration of customers in the electric and gas utility industries, municipalities, as well as natural gas producers. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepaymentsprepayment, or other forms of collateral. Management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to minimal credit risk. Our interstate transportation and storage operationssecurity. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considerconsiders many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability.
Our retail marketing segment extends credit to customers after a review of various credit indicators. Depending on the type of customer and its risk profile, security Increases in the formallowance are recorded as a component of a cash deposit, letter of creditoperating expenses; reductions in the allowance are recorded when receivables are subsequently collected or mortgages may be required.  Management records reserves for bad debt by computing a proportion of average write-off activity overwritten-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the past five years in comparison to the outstanding balance in accounts receivable.  This proportion is then applied to the accounts receivable balance at the end of the reporting period to calculate a current estimate of what is uncollectible. The allowance computation may then be adjusted to reflect input provided by the credit department and business line managers who may have specific knowledge of

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uncollectible items.  The credit department and business line managers make the decision to write off an account, based on understanding of the potential collectability.amount due.
We enter into netting arrangements with counterparties of derivative contractsto the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories
As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017.
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil petroleum and chemical products. Natural gas held in storage isspare parts, all of which are valued at the lower of cost or marketnet realizable value utilizing the weighted-average cost method. The cost of crude oil and petroleum and chemical products is determined using the last-in, first out method. The cost of appliances, parts and fittings is determined by the first-in, first-out method.

Inventories consisted of the following:
 December 31,
 2014 2013
Natural gas and NGLs$369
 $573
Crude oil364
 488
Refined products392
 543
Appliances, parts and fittings, and other264
 161
Total inventories$1,389
 $1,765
During the year ended December 31, 2014, the Partnership recorded write-downs of $473 million on its crude oil, refined products and NGL inventories as a result of a decline in the market price of these products. The write-down was calculated based upon current replacement costs.
 December 31,
 2017 2016
Natural gas, NGLs, and refined products$733
 $758
Crude oil551
 651
Spare parts and other305
 217
Total inventories$1,589
 $1,626
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Exchanges
Exchanges consist of natural gas and NGL delivery imbalances (over and under deliveries) with others. These amounts, which are valued at market prices or weighted average market prices pursuant to contractual imbalance agreements, turn over monthly and are recorded as exchanges receivable or exchanges payable on our consolidated balance sheets. These imbalances are generally settled by deliveries of natural gas or NGLs, but may be settled in cash, depending on contractual terms.
Other Current Assets
Other current assets consisted of the following:
December 31,December 31,
2014 20132017 2016
Deposits paid to vendors$65
 $49
$64
 $74
Deferred income taxes14
 —
Prepaid expenses and other192
 261
146
 224
Total other current assets$271
 $310
$210
 $298
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal

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labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
We review property,Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:
December 31,December 31,
2014 20132017 2016
Land and improvements$1,173
 $878
$1,706
 $676
Buildings and improvements (1 to 45 years)1,868
 900
1,960
 1,617
Pipelines and equipment (5 to 83 years)19,274
 16,966
44,050
 36,356
Natural gas and NGL storage facilities (5 to 46 years)1,215
 1,083
1,681
 1,452
Bulk storage, equipment and facilities (2 to 83 years)2,583
 1,933
3,036
 3,701
Tanks and other equipment (5 to 40 years)35
 1,685
Retail equipment (2 to 99 years)515
 450
Vehicles (1 to 25 years)158
 124
124
 217
Right of way (20 to 83 years)2,059
 1,901
3,424
 3,349
Furniture and fixtures (2 to 25 years)53
 48
Linepack117
 116
Pad gas44
 52
Other (1 to 30 years)919
 626
Natural resources434
 434
Other (1 to 40 years)534
 484
Construction work-in-process3,187
 1,668
10,750
 9,934
33,200
 28,430
67,699
 58,220
Less – Accumulated depreciation(3,457) (2,483)
Less – Accumulated depreciation and depletion(9,262) (7,303)
Property, plant and equipment, net$29,743
 $25,947
$58,437
 $50,917
We recognized the following amounts of depreciation expense for the periods presented:
 Years Ended December 31,
 2014 2013 2012
Depreciation expense$1,026
 $944
 $615
Capitalized interest, excluding AFUDC$99
 $43
 $99
 Years Ended December 31,
 2017 2016 2015
Depreciation and depletion expense$2,060
 $1,793
 $1,713
Capitalized interest283
 199
 163
Advances to and Investments in Unconsolidated Affiliates
We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies.
Goodwill
Goodwill An impairment of an investment in an unconsolidated affiliate is tested for impairment annually or more frequently ifrecognized when circumstances indicate that goodwill might be impaired. Our annual impairment test is performed as of August 31 for subsidiaries in our intrastate transportation and storage and midstream segments and during the fourth quarter for subsidiaries in our interstate transportation and storage, liquids

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transportation and services, and retail marketing segments and all others. We recorded goodwill impairments for the periods presented in these consolidated financial statements.
Changesa decline in the carrying amountinvestment value is other than temporary.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of goodwill were as follows:the following:
 
Intrastate
Transportation
and Storage
 
Interstate
Transportation and Storage
 Midstream Liquids Transportation and Services Investment in Sunoco Logistics Retail Marketing All Other Total
Balance, December 31, 2012$10
 $1,884
 $375
 $432
 $1,368
 $1,272
 $265
 $5,606
Goodwill acquired—
 —
 —
 —
 —
 156
 —
 156
Goodwill disposed—
 —
 (337) —
 —
 —
 —
 (337)
Goodwill impairment—
 (689) —
 —
 —
 —
 —
 (689)
Other—
 —
 (2) —
 (22) 17
 —
 (7)
Balance, December 31, 201310
 1,195
 36
 432
 1,346
 1,445
 265
 4,729
Goodwill acquired—
 —
 —
 —
 12
 1,862
 —
 1,874
Goodwill disposed—
 (184) —
 —
 —
 —
 —
 (184)
Balance, December 31, 2014$10
 $1,011
 $36
 $432
 $1,358
 $3,307
 $265
 $6,419
 December 31,
 2017 2016
Regulatory assets$85
 $86
Deferred charges210
 217
Restricted funds192
 190
Long-term affiliated receivable85
 90
Other186
 89
Total other non-current assets, net$758
 $672
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. We recorded a net increase in goodwill of $1.69 billion during the year ended December 31, 2014 primarily due to $1.73 billion(1)Includes unamortized financing costs related to the Susser Merger.Partnership’s revolving credit facilities.
During the fourth quarterRestricted funds primarily consisted of 2013, we performed a goodwill impairment test onrestricted cash held in our Lake Charles LNG reporting unit. In accordance with GAAP, we performed step one of the goodwill impairment test and determined that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount primarily due to changes related to (i) the structure and capitalization of the planned LNG export project at Lake Charles LNG’s Lake Charles facility, (ii) an analysis of current macroeconomic factors, including global natural gas prices and relative spreads, as of the date of our assessment, (iii) judgments regarding the prospect of obtaining regulatory approval for a proposed LNG export project and the uncertainty associated with the timing of such approvals, and (iv) changes in assumptions related to potential future revenues from the import facility and the proposed export facility. An assessment of these factors in the fourth quarter of 2013 led to a conclusion that the estimated fair value of the Lake Charles LNG reporting unit was less than its carrying amount.  We then applied the second step in the goodwill impairment test, allocating the estimated fair value of the reporting unit among all of the assets and liabilities of the reporting unit in a hypothetical purchase price allocation. The assets and liabilities of the reporting unit had recently been measured at fair value in 2012 as a result of the acquisition of Southern Union, and those estimated fair values had been recorded at the reporting unit through the application of “push-down” accounting. For purposes of the hypothetical purchase price allocation used in the goodwill impairment test, we estimated the fair value of the assets and liabilities of the reporting unit in a manner similar to the original purchase price allocation. In allocating value to the property, plant and equipment, we used current replacement costs adjusted for assumed depreciation. We also included the estimated fair value of working capital and identifiable intangible assets in the reporting unit. We adjusted deferred income taxes based on these estimated fair values. Based on this hypothetical purchase price allocation, estimated goodwill was $184 million, which was less than the balance of $873 million that had originally been recorded by the reporting unit through “push-down” accounting in 2012. As a result, we recorded a goodwill impairment of $689 million during the fourth quarter of 2013.wholly-owned captive insurance companies.
No other goodwill impairments were identified or recorded for our reporting units.
Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. We eliminate from our balance sheetThe Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.

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Components and useful lives of intangible assets were as follows:
 December 31, 2014 December 31, 2013
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:       
Customer relationships, contracts and agreements (3 to 46 years)$1,482
 $(267) $1,393
 $(164)
Patents (9 years)48
 (11) 48
 (6)
Trade Names (15 years)490
 —
 —
 —
Other (1 to 15 years)36
 (7) 4
 (1)
Total amortizable intangible assets$2,056
 $(285) $1,445
 $(171)
Non-amortizable intangible assets:       
Trademarks316
 —
 294
 —
Total intangible assets$2,372
 $(285) $1,739
 $(171)
 December 31, 2017 December 31, 2016
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:       
Customer relationships, contracts and agreements (3 to 46 years)$6,250
 $(1,003) $5,362
 $(737)
Patents (10 years)48
 (26) 48
 (21)
Trade Names (20 years)66
 (25) 66
 (22)
Other (5 to 20 years)1
 —
 2
 (2)
Total intangible assets$6,365
 $(1,054) $5,478
 $(782)
Aggregate amortization expense of intangible assets was as follows:
 Years Ended December 31,
 2014 2013 2012
Reported in depreciation and amortization$104
 $88
 $36
 Years Ended December 31,
 2017 2016 2015
Reported in depreciation, depletion and amortization$272
 $193
 $216
Estimated aggregate amortization expense for the next five years is as follows:
Years Ending December 31:  
2015$128
2016125
2017125
2018124
$280
2019121
278
2020278
2021268
2022256
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
Other Non-Current Assets, netIn 2015, we recorded $24 million of intangible asset impairments related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows.
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consistedGoodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of the following:goodwill were as follows:
 December 31,
 2014 2013
Unamortized financing costs (3 to 30 years)$63
 $70
Regulatory assets85
 86
Deferred charges220
 144
Restricted funds177
 378
Other148
 88
Total other non-current assets, net$693
 $766
 Intrastate
Transportation
and Storage		 Interstate
Transportation and Storage		 Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services All Other Total
Balance, December 31, 2015$10
 $912
 $718
 $772
 $912
 $2,104
 $5,428
Reduction due to contribution of legacy Sunoco, Inc. retail business—
 —
 —
 —
 —
 (1,289) (1,289)
Acquired—
 —
 177
 —
 251
 —
 428
Impaired—
 (638) (32) —
 —
 —
 (670)
Balance, December 31, 201610
 274
 863
 772
 1,163
 815
 3,897
Acquired—
 —
 8
 —
 4
 —
 12
Impaired—
 (262) —
 (79) —
 (452) (793)
Other—
 —
 (1) —
 —
 —
 (1)
Balance, December 31, 2017$10
 $12
 $870
 $693
 $1,167
 $363
 $3,115
Restricted fundsGoodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily consisteddue to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
During the fourth quarter of restricted2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash heldflows driven by declines in commodity prices and changes in the markets that these assets serve.
During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.
The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our wholly-owned captive insurance companies.

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Tableimpairment assessments are reasonable and based on available market information, but variations in any of Contentsthe assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.

Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted

risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts recorded by Panhandle, Sunoco Logistics and our retail marketing operations, discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 20142017 and 2013,2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes itWe believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
Below is a scheduleAs of AROs by segment recorded asDecember 31, 2017 and 2016, other non-current liabilities in ETP’sthe Partnership’s consolidated balance sheet:sheets included AROs of $165 million and $170 million, respectively.
 December 31,
 2014 2013
Interstate transportation and storage$58
 $55
Investment in Sunoco Logistics41
 41
Retail marketing87
 84
 $186
 $180
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
AsLong-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2014, there were no2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs.

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Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
December 31,December 31,
2014 20132017 2016
Interest payable$301
 $294
$443
 $440
Customer advances and deposits82
 126
59
 56
Accrued capital expenditures536
 166
1,006
 749
Accrued wages and benefits196
 155
208
 212
Taxes payable other than income taxes236
 214
108
 63
Income taxes payable50
 3
Deferred income taxes99
 119
Exchanges payable154
 208
Other274
 351
165
 177
Total accrued and other current liabilities$1,774
 $1,428
$2,143
 $1,905
Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests
The noncontrolling interest holders in one of our consolidated subsidiaries has the option to sell its interests to us.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheet.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Price risk management assets and liabilities are recorded at fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 20142017 was $20.40$34.28 billion and $19.34$33.09 billion, respectively. As of December 31, 2013,2016, the aggregate fair value and carrying amount of our debt obligations was $17.69$33.85 billion and $17.09$32.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives, and interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the periodyear ended December 31, 2014,2017, no transfers were made between any levels within the fair value hierarchy.

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The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 20142017 and 20132016 based on inputs used to derive their fair values:
Fair Value Total Fair Value Measurements at December 31, 2014Fair Value Total Fair Value Measurements at December 31, 2017
Level 1 Level 2Level 1 Level 2
Assets:          
Interest rate derivatives$3
 $—
 $3
Commodity derivatives:

         
Natural Gas:
         
Basis Swaps IFERC/NYMEX19
 19
 —
$11
 $11
 $—
Swing Swaps IFERC26
 1
 25
13
 —
 13
Fixed Swaps/Futures541
 541
 —
70
 70
 —
Forward Physical Swaps1
 —
 1
8
 —
 8
Power:

         
Forwards3
 —
 3
23
 —
 23
Futures4
 4
 —
Natural Gas Liquids – Forwards/Swaps46
 46
 —
193
 193
 —
Refined Products – Futures21
 21
 —
Crude – Futures2
 2
 —
Total commodity derivatives661
 632
 29
320
 276
 44
Other non-current assets21
 14
 7
Total assets$664
 $632
 $32
$341
 $290
 $51
Liabilities:

 
 

     
Interest rate derivatives$(155) $—
 $(155)$(219) $—
 $(219)
Commodity derivatives:          
Natural Gas:

         
Basis Swaps IFERC/NYMEX(18) (18) —
(24) (24) —
Swing Swaps IFERC(25) (2) (23)(15) (1) (14)
Fixed Swaps/Futures(490) (490) —
(57) (57) —
Power:

    
Forwards(4) —
 (4)
Futures(2) (2) —
Forward Physical Swaps(2) —
 (2)
Power – Forwards(22) —
 (22)
Natural Gas Liquids – Forwards/Swaps(32) (32) —
(192) (192) —
Refined Products – Futures(7) (7) —
(25) (25) —
Crude – Futures(1) (1) —
Total commodity derivatives(578) (551) (27)(338) (300) (38)
Total liabilities$(733) $(551) $(182)$(557) $(300) $(257)

S - 26

Fair Value
Total
 Fair Value Measurements at December 31, 2013Fair Value Total Fair Value Measurements at December 31, 2016
Level 1 Level 2Level 1 Level 2 Level 3
Assets:            
Interest rate derivatives$47
 $—
 $47
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX5
 5
 —
Swing Swaps IFERC8
 1
 7
Fixed Swaps/Futures201
 201
 —
Power:     
Forwards3
 —
 3
Natural Gas Liquids – Forwards/Swaps5
 5
 —
Refined Products – Futures5
 5
 —
Total commodity derivatives227
 217
 10
Total assets$274
 $217
 $57
Liabilities:     
Interest rate derivatives$(95) $—
 $(95)
Commodity derivatives:            
Natural Gas:            
Basis Swaps IFERC/NYMEX(4) (4) —
$14
 $14
 $—
 $—
Swing Swaps IFERC(6) —
 (6)2
 —
 2
 —
Fixed Swaps/Futures(201) (201) —
96
 96
 —
 —
Forward Physical Swaps(1) —
 (1)1
 —
 1
 —
Power:            
Forwards(1) —
 (1)4
 —
 4
 —
Futures1
 1
 —
 —
Options – Calls1
 1
 —
 —
Natural Gas Liquids – Forwards/Swaps(5) (5) —
233
 233
 —
 —
Refined Products – Futures(5) (5) —
1
 1
 —
 —
Crude – Futures9
 9
 —
 —
Total commodity derivatives362
 355
 7
 —
Other non-current assets13
 8
 5
 —
Total assets$375
 $363
 $12
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in the Legacy ETP Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) —
 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids – Forwards/Swaps(273) (273) —
 —
Refined Products – Futures(17) (17) —
 —
Crude – Futures(13) (13) —
 —
Total commodity derivatives(223) (215) (8)(472) (464) (8) —
Total liabilities$(318) $(215) $(103)$(666) $(464) $(201) $(1)
At December 31, 2013, the fair value of the Lake Charles LNG reporting unit was classified as Level 3 of the fair value hierarchy due to the significance of unobservable inputs developed using company-specific information. We used the income approach to measure the fair value of the Lake Charles LNG reporting unit. Under the income approach, we calculated the fair value based on the present value of the estimated future cash flows. The discount rate used, which was an unobservable input, was based on the weighted-average cost of capital adjusted for the relevant risk associated with business-specific characteristics and the uncertainty related to the business's ability to execute on the projected cash flows.
ContributionsCommon Units
The change in Aid of Construction CostsETE Common Units during the years ended December 31, 2017, 2016 and 2015 was as follows:
 Years Ended December 31,
 2017 2016 2015
Number of Common Units, beginning of period1,046.9
 1,044.8
 1,077.5
Conversion of Class D Units to ETE Common Units—
 —
 0.9
Repurchase of common units under buyback program—
 —
 (33.6)
Issuance of common units32.2
 2.1
 —
Number of Common Units, end of period1,079.1
 1,046.9
 1,044.8
ETE Equity Distribution Agreement
In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the year ended December 31, 2017.
ETE Series A Convertible Preferred Units
 Years Ended December 31,
 2017 2016 2015
Number of Series A Convertible Preferred Units, beginning of period329.3
 —
 —
Issuance of Series A Convertible Preferred Units—
 329.3
 —
Number of Series A Convertible Preferred Units, end of period329.3
 329.3
 —
On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain of our capital projects, third parties are obligatedcommon unitholders (“Electing Unitholders”) who elected to reimburse us for all orparticipate in a plan to forgo a portion of project expenditures. The majoritytheir future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such arrangementsparticipating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are associatedexpected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.
The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with pipeline constructionrespect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and production well tie-ins. Contributionsany Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in aidthe carrying amount of construction costs (“CIAC”)the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 2017.
ETE issued 329,295,770 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s

Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.
ETE January 2017 Private Placement and ETP Unit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 23.7 million newly issued ETP common units for approximately $568 million.
Common Unit Split
On July 27, 2015, ETE completed a two-for-one split of the Partnership’s outstanding common units by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015.
Repurchase Program
In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 33.6 million ETE Common Units under this program in 2015. No units were repurchased under this program in 2017 or 2016, and there was $936 million available to use under the program as of December 31, 2017.
Class D Units
In 2013, the Partnership issued 3,080,000 Class D Units of ETE pursuant to an agreement with a former executive. The Class D Units were convertible to ETE Common Units, subject to certain vesting requirements which were not met prior to the former executive’s termination in 2016.
Sale of Common Units by Subsidiaries
The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented.
Sale of Common Units by ETP
ETP’s Equity Distribution Program
From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are netted against our project costsmade by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion.

During the year ended December 31, 2017, ETP issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $752 million of ETP’s Common Units remained available to be issued under ETP’s currently effective equity distribution agreement.
ETP’s Equity Incentive Plan Activity
ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are received,entitled withheld by ETP to satisfy tax-withholding obligations.
ETP’s Distribution Reinvestment Program
ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and any CIACbeneficial owners of ETP Common Units a voluntary means by which exceeds our total project costs, is recognized as other incomethey can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the periodpurchase of additional ETP Common Units.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan.
During the years ended December 31, 2017, 2016 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in which it is realized.

S - 27
Tablethe issuance in aggregate of Contents25.5 million Common Units.
As of December 31, 2017, a total of 20.8 million Common Units remain available to be issued under the existing registration statement.

ShippingAugust 2017 Units Offering
In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and Handling Costsfor general partnership purposes.
Shipping and handling costsETP Class E Units
There are included in costcurrently 8.9 million ETP Class E Units outstanding, all of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are includedcurrently owned by HHI. The ETP Class E Units generally do not have any voting rights. The ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the Class E Unitholders, up to $1.41 per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in operating expenses.ETP’s consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the ETP Class E Units at a future date.
CostsETP Class G Units
There are currently 90.7 million ETP Class G Units outstanding, all of which are held by wholly-owned subsidiaries of ETP. The ETP Class G Units generally do not have any voting rights. The ETP Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and Expenses
Costsits subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of products sold include actual cost$3.75 per ETP Class G Unit per year. Allocations of fuel sold, adjusteddepreciation and amortization to the ETP Class G Units for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We record the collection of taxes to be remitted to government authoritiestax purposes are based on a predetermined percentage and are not contingent on whether ETP has net basis except for our retail marketing segment in which consumer excise taxes on sales of refined products and merchandiseincome or loss. These units are included in both revenues and costs and expensesreflected as treasury units in the consolidated statementsfinancial statements.
ETP Class H Units
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.

ETP Class I Units
In connection with the Bakken Pipeline Transaction discussed in Note 3, in March 2015, ETP issued 100 ETP Class I Units. The ETP Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the ETP Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the ETP Class I Units and (ii) after making cash distributions to ETP Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in ETP’s Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
Class K Units
On December 29, 2016, ETP issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in ETP, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. If ETP is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2017, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETP.
Sales of Common Units by Sunoco Logistics
Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.
In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated.
ETP Series A and Series Preferred Units
In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit.
Distributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15,

2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.
Sales of Common Units by Sunoco LP
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.
In October 2016, Sunoco LP entered into an equity distribution agreement pursuant to which Sunoco LP may sell from time to time common units having aggregate offering prices of up to $400 million. Through December 31, 2016, Sunoco LP received net proceeds of $71 million from the issuance of 2.8 million Sunoco LP common units pursuant to such equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. From January 1, 2017 through December 31, 2017, Sunoco LP issued additional 1.3 million units with total net proceeds of $33 million, net of commissions of $0.3 million. As of December 31, 2017, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP.
On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership.
In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha Petroleum, Ltd as consideration for the contribution by Aloha to an indirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries.
In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million. The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility.
Sunoco LP Series A Preferred Units
On March 30, 2017, the Partnership purchased 12.0 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units is10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference.
In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.
Contributions to Subsidiaries
The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain

its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest.
Parent Company Quarterly Distributions of Available Cash
Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Sunoco LP related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG.
Our distributions declared and paid with respect to our common units for the periods presented were as follows:
Quarter Ended        Record DatePayment DateRate
December 31, 2014February 6, 2015February 19, 20150.2250
March 31, 2015May 8, 2015May 19, 20150.2450
June 30, 2015August 6, 2015August 19, 20150.2650
September 30, 2015November 5, 2015November 19, 20150.2850
December 31, 2015February 4, 2016February 19, 20160.2850
March 31, 2016 (1)
May 6, 2016May 19, 20160.2850
June 30, 2016 (1)
August 8, 2016August 19, 20160.2850
September 30, 2016 (1)
November 7, 2016November 18, 20160.2850
December 31, 2016 (1)
February 7, 2017February 21, 20170.2850
March 31, 2017 (1)
May 10, 2017May 19, 20170.2850
June 30, 2017 (1)
August 7, 2017August 21, 20170.2850
September 30, 2017 (1)
November 7, 2017November 20, 20170.2950
December 31, 2017 (1)
February 8, 2018February 20, 20180.3050
(1)
Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See additional information below.
Our distributions declared and paid with respect to our Convertible Unit during the years ended December 31, 2016 and 2017 were as follows:
Quarter Ended          Record Date Payment Date  Rate
March 31, 2016 May 6, 2016 May 19, 2016 $0.1100
June 30, 2016 August 8, 2016 August 19, 2016 0.1100
September 30, 2016 November 7, 2016 November 18, 2016 0.1100
December 31, 2016 February 7, 2017 February 21, 2017 0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100
December 31, 2017 February 8, 2018 February 20, 2018 0.1100
ETP’s Quarterly Distributions of Available Cash
Under ETP’s limited partnership agreement, within 45 days after the end of each quarter, ETP distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct ETP’s business. ETP will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.

If cash distributions exceed $0.0833 per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”
As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount IDRs 
Partners (1)
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%
(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:
Quarter Ended ETP Sunoco Logistics
December 31, 2014 $0.6633
 $0.4000
March 31, 2015 0.6767
 0.4190
June 30, 2015 0.6900
 0.4380
September 30, 2015 0.7033
 0.4580
December 31, 2015 0.7033
 0.4790
March 31, 2016 0.7033
 0.4890
June 30, 2016 0.7033
 0.5000
September 30, 2016 0.7033
 0.5100
December 31, 2016 0.7033
 0.5200
Distributions on common units declared and paid by Post-Merger ETP were as follows:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 16, 2017 $0.5350
June 30, 2017 August 7, 2017 August 15, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
December 31, 2017 February 8, 2018 February 14, 2018 0.5650

In connection with no effectprevious transactions, we have agreed to relinquish its right to the following amounts of incentive distributions in future periods:
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Distributions declared and paid by ETP to the Series A and Series B preferred unitholders were as follows:
 Distribution per Preferred Unit
Quarter Ended Record Date Payment Date Series A Series B
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
 $16.378
Sunoco LP Quarterly Distributions of Available Cash
The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Effective July 1, 2015, ETE exchanged 21 million ETP common units, owned by ETE, the owner of ETP’s general partner interest, for 100% of the general partner interest and all of the IDRs of Sunoco LP. ETP had previously owned our IDRs since September 2014, prior to that date the IDRs were owned by Susser.
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs
Minimum Quarterly Distribution $0.4375 100% —%
First Target Distribution $0.4375 to $0.503125 100% —%
Second Target Distribution $0.503125 to $0.546875 85% 15%
Third Target Distribution $0.546875 to $0.656250 75% 25%
Thereafter Above $0.656250 50% 50%

Distributions declared and paid by Sunoco LP for the periods presented were as follows:
Quarter EndedRecord DatePayment DateRate
December 31, 2014February 17, 2015February 27, 20150.6000
March 31, 2015May 19, 2015May 29, 20150.6450
June 30, 2015August 18, 2015August 28, 20150.6934
September 30, 2015November 17, 2015November 27, 20150.7454
December 31, 2015February 5, 2016February 16, 20160.8013
March 31, 2016May 6, 2016May 16, 20160.8173
June 30, 2016August 5, 2016August 15, 20160.8255
September 30, 2016November 7, 2016November 15, 20160.8255
December 31, 2016February 13, 2017February 21, 20170.8255
March 31, 2017May 9, 2017May 16, 20170.8255
June 30, 2017August 7, 2017August 15, 20170.8255
September 30, 2017November 7, 2017November 14, 20170.8255
December 31, 2017February 06, 2018February 14, 20180.8255
Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
 December 31,
 2017 2016
Available-for-sale securities$8
 $2
Foreign currency translation adjustment(5) (5)
Actuarial gain (loss) related to pensions and other postretirement benefits(5) 7
Investments in unconsolidated affiliates, net5
 4
Subtotal3
 8
Amounts attributable to noncontrolling interest(3) (8)
Total AOCI included in partners’ capital, net of tax$—
 $—
The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss). Excise taxes collected:
 December 31,
 2017 2016
Available-for-sale securities$(2) $(2)
Foreign currency translation adjustment3
 3
Actuarial loss relating to pension and other postretirement benefits3
 —
Total$4
 $1
9.UNIT-BASED COMPENSATION PLANS:
We, ETP and Sunoco LP have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards.
ETE Long-Term Incentive Plan
The Board of Directors or the Compensation Committee of the board of directors of our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom

units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 12.0 million units. As of December 31, 2017, 10.8 million units remain available to be awarded under the plan.
During the year ended December 31, 2017, 1.2 million ETE unit awards were granted to ETE employees and certain employees of ETP and 15,648 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest 60% in three years and 40% in five years and do not entitle the holders to receive distributions during the vesting period.
During the year ended December 31, 2017 and 2016, a total of 2,018 and 28,648 ETE Common Units vested, with a total fair value of $39 thousand and $205 thousand, respectively, as of the vesting date. As of December 31, 2017, a total of 1,251,002 restricted units remain outstanding, for which we expect to recognize a total of $21 million in compensation over a weighted average period of 3.5 years.
Subsidiary Unit-Based Compensation Plans
Each of ETP and Sunoco LP has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards” to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a five-year period, and vesting The Subsidiary Unit Awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by our retail marketing segment were $2.46 billion, $2.22 billion and $573 millionthe respective subsidiaries during the period the restricted unit is outstanding.
The following table summarizes the activity of the Subsidiary Unit Awards:
 ETP Sunoco LP
 
Number of
Units
 
Weighted  Average
Grant-Date Fair Value
Per Unit
 
Number of
Units
 
Weighted  Average
Grant-Date Fair Value
Per Unit
Unvested awards as of December 31, 20169.4
 $27.68
 2.0
 $34.43
Legacy Sunoco Logistics unvested awards as of December 31, 20163.2
 28.57
 —
 —
Awards granted4.9
 17.69
 0.2
 28.31
Awards vested(2.3) 34.22
 (0.3) 45.48
Awards forfeited(1.1) 25.03
 (0.2) 34.71
Unvested awards as of December 31, 201714.1
 23.18
 1.7
 31.89
Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31:       
2017  $17.69
   $28.31
2016  23.82
   26.95
2015  23.47
   40.63
The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2014, 20132017, 2016, and 2012, respectively.2015 was $40 million, $40 million, and $57 million, respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $216 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.8 years.
Income Taxes
10.INCOME TAXES:
ETP isAs a publicly traded limited partnership, and iswe are not taxable forsubject to United States federal income tax and most state income tax purposes. As a result, our earnings or losses, totaxes. However, the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2014, 2013 and 2012, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:
 Years Ended December 31,
 2017 2016 2015
Current expense (benefit):     
Federal$54
 $(47) $(308)
State(16) (34) (54)
Total38
 (81) (362)
Deferred expense (benefit):     
Federal(2,055) (189) 268
State184
 12
 (29)
Total(1,871) (177) 239
Total income tax expense (benefit) from continuing operations$(1,833) $(258) $(123)
Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense (benefit) at the United States statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2017, 2016 and 2015 is as follows:
 2017 2016 2015
Income tax expense (benefit) at United States statutory rate of 35 percent$248
 $71
 $316
Increase (reduction) in income taxes resulting from:     
Partnership earnings not subject to tax(477) (576) (355)
Goodwill impairment207
 278
 —
State tax, net of federal tax benefit124
 (10) (29)
Dividend received deduction(14) (15) (22)
Federal rate change(1,812) —
 —
Audit settlement—
 —
 (7)
Change in tax status of subsidiary(124) —
 —
Other15
 (6) (26)
Income tax expense (benefit) from continuing operations$(1,833) $(258) $(123)

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
 December 31,
 2017 2016
Deferred income tax assets:   
Net operating losses and alternative minimum tax credit$683
 $472
Pension and other postretirement benefits21
 30
Long-term debt14
 32
Other191
 182
Total deferred income tax assets909
 716
Valuation allowance(189) (118)
Net deferred income tax assets720
 598
    
Deferred income tax liabilities:   
Property, plant and equipment(1,036) (1,633)
Investments in unconsolidated affiliates(2,726) (3,789)
Trademarks(173) (273)
Other(100) (15)
Total deferred income tax liabilities(4,035) (5,710)
Net deferred income taxes$(3,315) $(5,112)
The table below provides a rollforward of the net deferred income tax liability as follows:
 December 31,
 2017 2016
Net deferred income tax liability, beginning of year$(5,112) $(4,590)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)—
 (460)
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3)—
 (243)
Tax provision, including provision from discontinued operations1,825
 201
Other(28) (20)
Net deferred income tax liability$(3,315) $(5,112)
ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $403 million, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $62 million of federal alternative minimum tax credits at December 31, 2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have net operating loss carryforward benefits of $274 million, $217 million net of federal tax, which expire between January 1, 2018 and 2037. A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.

The following table sets forth the changes in unrecognized tax benefits:
 Years Ended December 31,
 2017 2016 2015
Balance at beginning of year$615
 $610
 $440
Additions attributable to tax positions taken in the current year—
 8
 178
Additions attributable to tax positions taken in prior years28
 18
 —
Reduction attributable to tax positions taken in prior years(25) (20) —
Lapse of statute(9) (1) (8)
Balance at end of year$609
 $615
 $610
As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $9 million, net of tax.
Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in its litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2017.
In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety.  In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact.  Nextel has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court.  Sunoco, Inc. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter.  However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 million after federal income tax benefits) against the receivable.
In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.
Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments.
ETE and its subsidiaries also have various state and local income taxes. Thesetax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.
Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate subsidiaries include Susserfederal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefit of $1.81 billion in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

11.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Contingent Residual Support Agreement – AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.
Guarantee of Sunoco LP Notes
In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
$1.00 billion aggregate principal amount of 4.875%, senior notes due 2023;
$800 million aggregate principal amount of 5.50% senior notes due 2026; and
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.
FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.
Commitments
In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.
ETP’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
  Years Ended December 31,
  2017 2016 2015
Rental expense(1)
 $196
 $187
 $281
Less: Sublease rental income (25) (26) (26)
Rental expense, net $171
 $161
 $255
(1)
Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Future minimum lease commitments for such leases are:
Years Ending December 31: 
2018$113
2019100
202096
202183
202271
Thereafter606
Future minimum lease commitments1,069
Less: Sublease rental income(152)
Net future minimum lease commitments$917
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
Dakota Access Pipeline
On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.
After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.
The SRST appealed the denial of the preliminary injunction to the United States Court of Appeals for the D.C. Circuit and filed an emergency motion in the United States District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.
In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the Tribe. The District Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.

The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes.
On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018.
On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access is required to file the revised plan with the Court by April 1, 2018. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first report was filed with the court on December 29, 2017.
In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. Briefing on YST’s motion is ongoing.
While we believe that the pending lawsuits are unlikely to halt or suspend the operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.
MTBE Litigation
Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2017, Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco which owns Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is

pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland.
Sunoco, Inc. and Panhandle.Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The PartnershipCourt approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Regency Merger Litigation
Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”).
The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its corporate subsidiaries accountentirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC.
The Regency Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for income taxesrehearing to the Court of Appeals was denied. ETP filed a petition for review with the Texas Supreme Court. Enterprise’s response is due February 26, 2018.
Sunoco Logistics Merger Litigation
Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well

as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017.
The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger.
Litigation Filed By or Against Williams
On April 6, 2016, Williams filed a complaint, The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the assetMerger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and liability method.(b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.
UnderOn May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions.
ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.
After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.
Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Defendants breached an additional representation and warranty in the Merger Agreement.
Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On

September 29, 2016, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016.
On March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial and denied Williams’ motion for reargument on April 5, 2017. As a result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.
Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this method, deferred tax assetsfiling; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.
Unitholder Litigation Relating to the Issuance
In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.
The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.
The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is currently set for February 19-21, 2018.
The Issuance Defendants cannot predict the outcome of the Issuance Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation. The Issuance Defendants believe the Issuance Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Issuance.
Litigation filed by BP Products
On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.
SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.
On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.
Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2017 and 2016, accruals of approximately $33 million and $77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
No amounts have been recorded in our December 31, 2017 or 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are recognized difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million

for the estimated future tax consequences attributablethree releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to differences betweenresolve the financial statement carrying amountsCaddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of existingEnvironmental Quality.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and liabilitiesother formerly owned sites.
Sunoco, Inc. is potentially subject to joint and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effectseveral liability for the yearcosts of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 43 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in which those temporary differencesthe amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoveredrecoverable through tariffs or settled. rates are recorded as regulatory assets on our consolidated balance sheets.
The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets totable below reflects the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions areaccrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements only after determiningstatements.
 December 31,
 2017 2016
Current$35
 $26
Non-current337
 318
Total environmental liabilities$372
 $344

In 2013, we established a more-likely-than-not probabilitywholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change,captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains andaccrue losses offset related resultsattributable to unasserted claims based on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.
At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be

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measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivativesdiscounted estimates that are used to develop the premiums paid to the captive insurance company.
During the years ended December 31, 2017 and 2016, the Partnership recorded $32 million and $43 million, respectively, of expenditures related to environmental cleanup programs.
On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (TRC) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period.  On January 2, 2013, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations.  To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery.  Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to its results of operations, cash flows or financial position.
Our pipeline operations are subject to regulation by the United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
In January 2012, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas.  The proposed penalties are in excess of $100,000. The case went to hearing in November 2016 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.

In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our hedging transactions are highly effective in offsetting changes in cash flows. If we determineoperations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a derivativematerial adverse effect on our results of operations but there is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changesassurance that such costs will not be material in the future.
12.DERIVATIVE ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream operations whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the derivative in net incomeproceeds based on an index price for the period.residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
If we designateWe utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations. These contracts are not designated as hedges for accounting purposes.
We use financial commodity hedging relationship as a fair value hedge, we record the changesderivatives to take advantage of market opportunities in fair value of the hedged asset or liabilityour trading activities which complement our transportation and storage operations’ and are netted in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness isWe also included in the cost of products sold in the consolidated statements of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operatinghave trading and marketing activities in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remainpower and natural gas in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recordedour all other operations which are also netted in cost of products sold in the consolidated statements of operations.
We managesold. As a portionresult of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Unit-Based Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date,trading activities and the fair value is recordeduse of derivative financial instruments in other non-current liabilities on our consolidated balance sheets.
Pensionstransportation and Other Postretirement Benefit Plans
Employers are requiredstorage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to recognize in their balance sheetsperiod. We attempt to manage this volatility through the overfunded or underfunded statususe of defined benefit pensiondaily position and other postretirement plans, measured as the difference between the fair valueprofit and loss reports provided to our risk oversight committee, which includes members of the plan assetssenior management, and the benefit obligation (the projected benefit obligation for pension planslimits and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Employers must recognize the change in the funded status of the plan in the year in which the change occurs through AOCI in equity or are reflected as a regulatory asset or regulatory liability for regulated subsidiaries.
Allocation of Income
For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAPauthorizations set forth in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.

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3.ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
Pending Transactioncommodity risk management policy.
Regency Merger
In January 2015, ETP and Regency entered into a definitive merger agreement, as amended on February 18, 2015 (the “Merger Agreement”), pursuant to which Regency will merge with a wholly-owned subsidiary of ETP, with Regency continuing as the surviving entity and becoming a wholly-owned subsidiary of ETP (the “Regency Merger”). At the effective time of the Regency Merger (the “Effective Time”), each Regency common unit and Class F unit will be converted into the right to receive 0.4066 ETP Common Units, plus a number of additional ETP Common Units equal to $0.32 per Regency common unit divided by the lesser of (i) the volume weighted average price of ETP Common Units for the five trading days ending on the third trading day immediately preceding the Effective Time and (ii) the closing price of ETP Common Units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Regency series A preferred unit will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. The transaction is subject to other customary closing conditions including approval by Regency’s unitholders.
In addition, ETE, which owns the general partner and 100% of the incentive distribution rights of both Regency and ETP, has agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five year period. The IDR subsidy will be $80 million in the first year post closing and $60 million per year for the following four years. The transaction is expected to close in the second quarter of 2015.
ETP and Regency are under common control of ETE; therefore, we expect to account for the Regency Merger at historical cost as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements will be retrospectively adjusted to reflect consolidation of Regency beginning May 26, 2010 (the date ETE acquired Regency’s general partner).
2014 Transactions
Susser Merger
In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens our retail geographic footprint and provides synergy opportunities and a platform for future growth.
In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.
Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the Susser Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Our consolidated balance sheet as of December 31, 2014 reflected the preliminary purchase price allocations based on available information. Management is reviewing the valuation and confirming the results to determine the final purchase price allocation.

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The following table summarizes the preliminary assets acquired and liabilities assumed recognized as of the merger date:details our outstanding commodity-related derivatives:
  Susser
Total current assets $446
Property, plant and equipment 1,069
Goodwill(1)
 1,734
Intangible assets 611
Other non-current assets 17
  3,877
   
Total current liabilities 377
Long-term debt, less current maturities 564
Deferred income taxes 488
Other non-current liabilities 39
Noncontrolling interest 626
  2,094
Total consideration 1,783
Cash received 67
Total consideration, net of cash received $1,716
(1)
None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed is being determined using various valuation techniques, including the income and market approaches.
ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2014. Our consolidated statements of operations for the year ended December 31, 2014 reflected revenue and net income related to Susser of $2.32 billion and $105 million, respectively.
No pro forma information has been presented, as the impact of these acquisitions was not material in relation to ETP’s consolidated results of operations.
MACS to Sunoco LP
In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units.
Lake Charles LNG Transaction
On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). This transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG, including goodwill of $184 million and intangible assets of $50 million related to Lake Charles LNG. The results of Lake Charles LNG’s operations have not been presented as discontinued operations and Lake Charles LNG’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements due to the continuing involvement among the entities.
In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year

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for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 8.
Panhandle Merger
On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% senior notes due 2024, 8.25% senior notes due 2029 and the junior subordinated notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F Units), and ETP (2.2 million Common Units). In connection with the Panhandle Merger, Panhandle also assumed PEPL Holdings’ guarantee of $600 million of Regency senior notes.
2013 Transactions
Sale of Southern Union’s Distribution Operations
In December 2012, Southern Union entered into a purchase and sale agreement with The Laclede Group, Inc., pursuant to which Laclede Missouri agreed to acquire the assets of Southern Union’s MGE division and Laclede Massachusetts agreed to acquire the assets of Southern Union’s NEG division (together, the “LDC Disposal Group”). Laclede Gas Company, a subsidiary of The Laclede Group, Inc., subsequently assumed all of Laclede Missouri’s rights and obligations under the purchase and sale agreement. In February 2013, The Laclede Group, Inc. entered into an agreement with Algonquin Power & Utilities Corp (“APUC”) that allowed a subsidiary of APUC to assume the rights of The Laclede Group, Inc. to purchase the assets of Southern Union’s NEG division.
In September 2013, Southern Union completed its sale of the assets of MGE for an aggregate purchase price of $975 million, subject to customary post-closing adjustments. In December 2013, Southern Union completed its sale of the assets of NEG for cash proceeds of $40 million, subject to customary post-closing adjustments, and the assumption of $20 million of debt.
The LDC Disposal Group’s operations have been classified as discontinued operations for all periods in the consolidated statements of operations.
The following table summarizes selected financial information related to Southern Union’s distribution operations in 2013 through MGE and NEG’s sale dates in September 2013 and December 2013, respectively, and for the period from March 26, 2012 to December 31, 2012:
 Years Ended December 31,
 2013 2012
Revenue from discontinued operations$415
 $324
Net income of discontinued operations, excluding effect of taxes and overhead allocations65
 43
SUGS Contribution
On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (the “SUGS Contribution”). The general partner and IDRs of Regency are owned by ETE. The consideration paid by Regency in connection with this transaction consisted of (i) the issuance of approximately 31.4 million Regency common units to Southern Union, (ii) the issuance of approximately 6.3 million Regency Class F units to Southern Union, (iii) the distribution of $463 million in cash to Southern Union, net of closing adjustments, and (iv) the payment of $30 million in cash to a subsidiary of ETP. This transaction was between commonly controlled entities; therefore, the amounts recorded in the consolidated balance sheet for the investment in Regency and the related deferred tax liabilities were based on the historical book value of SUGS. In addition, PEPL Holdings provided a guarantee of collection with respect to the payment of the principal amounts of Regency’s debt related to the SUGS Contribution. The Regency Class F units have the same rights, terms and conditions as the Regency common units, except that Southern Union will not receive distributions on the Regency Class F units for the first eight consecutive quarters following the closing, and the Regency Class F units will thereafter automatically convert into Regency common units on a one-for-one basis. The Partnership has not presented SUGS as discontinued operations due to the Partnership’s

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continuing involvement with SUGS through affiliate relationships, as well as the direct investment in Regency common and Class F units received, which has been accounted for using the equity method.
Acquisition of ETE’s ETP Holdco Interest
On April 30, 2013, ETP acquired ETE’s 60% interest in ETP Holdco for approximately 49.5 million of newly issued ETP Common Units and $1.40 billion in cash, less $68 million of closing adjustments (the “ETP Holdco Acquisition”). As a result, ETP now owns 100% of ETP Holdco. ETE, which owns the general partner and IDRs of ETP, agreed to forego incentive distributions on the newly issued ETP units for each of the first eight consecutive quarters beginning with the quarter in which the closing of the transaction occurred and 50% of incentive distributions on the newly issued ETP units for the following eight consecutive quarters. ETP controlled ETP Holdco prior to this acquisition; therefore, the transaction did not constitute a change of control.
2012 Transactions
Southern Union Merger
On March 26, 2012, ETE completed its acquisition of Southern Union. Southern Union was the surviving entity in the merger and operated as a wholly-owned subsidiary of ETE. See below for discussion of ETP Holdco Transaction and ETE’s contribution of Southern Union to ETP Holdco.
Under the terms of the merger agreement, Southern Union stockholders received a total of 57 million ETE Common Units and a total of approximately $3.01 billion in cash. Effective with the closing of the transaction, Southern Union’s common stock was no longer publicly traded.
Citrus Acquisition
In connection with the Southern Union Merger on March 26, 2012, we completed our acquisition of CrossCountry, a subsidiary of Southern Union which owned an indirect 50% interest in Citrus, the owner of FGT. The total merger consideration was approximately $2.0 billion, consisting of approximately $1.9 billion in cash and approximately 2.2 million ETP Common Units. See Note 4 for more information regarding our equity method investment in Citrus.
Sunoco Merger
On October 5, 2012, ETP completed its merger with Sunoco, Inc. Under the terms of the merger agreement, Sunoco, Inc. shareholders received 55 million ETP Common Units and a total of approximately $2.6 billion in cash.
Sunoco, Inc. generates cash flow from a portfolio of retail outlets for the sale of gasoline and middle distillates in the east coast, midwest and southeast areas of the United States. Prior to October 5, 2012, Sunoco, Inc. also owned a 2% general partner interest, 100% of the IDRs, and 32% of the outstanding common units of Sunoco Logistics. As discussed below, on October 5, 2012, Sunoco, Inc.’s interests in Sunoco Logistics were transferred to the Partnership.
Prior to the Sunoco Merger, on September 8, 2012, Sunoco, Inc. completed the exit from its Northeast refining operations by contributing the refining assets at its Philadelphia refinery and various commercial contracts to PES, a joint venture with The Carlyle Group. Sunoco, Inc. also permanently idled the main refining processing units at its Marcus Hook refinery in June 2012. The Marcus Hook Industrial Complex continued to support operations at the Philadelphia refinery prior to commencement of the PES joint venture. Under the terms of the joint venture agreement, The Carlyle Group contributed cash in exchange for a 67% controlling interest in PES. In exchange for contributing its Philadelphia refinery assets and various commercial contracts to the joint venture, Sunoco, Inc. retained an approximate 33% non-operating noncontrolling interest. The fair value of Sunoco, Inc.’s retained interest in PES, which was $75 million on the date on which the joint venture was formed, was determined based on the equity contributions of The Carlyle Group. Sunoco, Inc. has indemnified PES for environmental liabilities related to the Philadelphia refinery that arose from the operation of such assets prior the formation of the joint venture. The Carlyle Group will oversee day-to-day operations of PES and the refinery. JPMorgan Chase provides working capital financing to PES in the form of an asset-backed loan, supply crude oil and other feedstocks to the refinery at the time of processing and purchase certain blendstocks and all finished refined products as they are processed. Sunoco, Inc. entered into a supply contract for gasoline and diesel produced at the refinery for its retail marketing business.
ETP incurred merger related costs related to the Sunoco Merger of $28 million during the year ended December 31, 2012. Sunoco, Inc.’s revenue included in our consolidated statement of operations was approximately $5.93 billion during October through December 2012. Sunoco, Inc.’s net loss included in our consolidated statement of operations was approximately $14 million during October through December 2012. Sunoco Logistics’ revenue included in our consolidated statement of

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operations was approximately $3.11 billion during October through December 2012. Sunoco Logistics’ net income included in our consolidated statement of operations was approximately $145 million during October through December 2012.
ETP Holdco Transaction
Immediately following the closing of the Sunoco Merger in 2012, ETE contributed its interest in Southern Union into ETP Holdco, an ETP-controlled entity, in exchange for a 60% equity interest in ETP Holdco. In conjunction with ETE’s contribution, ETP contributed its interest in Sunoco, Inc. to ETP Holdco and retained a 40% equity interest in ETP Holdco. Prior to the contribution of Sunoco, Inc. to ETP Holdco, Sunoco, Inc. contributed $2.0 billion of cash and its interests in Sunoco Logistics to ETP in exchange for 90.7 million Class F Units representing limited partner interests in ETP (“Class F Units”). The Class F Units were exchanged for Class G Units in 2013 as discussed in Note 8. Pursuant to a stockholders agreement between ETE and ETP, ETP controlled ETP Holdco (prior to ETP’s acquisition of ETE’s 60% equity interest in ETP Holdco in 2013) and therefore, ETP consolidated ETP Holdco (including Sunoco, Inc. and Southern Union) in its financial statements subsequent to consummation of the ETP Holdco Transaction.
Under the terms of the ETP Holdco transaction agreement, ETE agreed to relinquish its right to $210 million of incentive distributions from ETP that ETE would otherwise be entitled to receive over 12 consecutive quarters beginning with the distribution paid on November 14, 2012.
In accordance with GAAP, we have accounted for the ETP Holdco Transaction, whereby ETP obtained control of Southern Union, as a reorganization of entities under common control. Accordingly, ETP’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Southern Union into ETP beginning March 26, 2012 (the date ETE acquired Southern Union). This change only impacted interim periods in 2012, and no prior annual amounts have been adjusted.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the Sunoco Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Upon consummation of the ETP Holdco Transaction, we applied the accounting guidance for transactions between entities under common control. In doing so, we recorded the values of assets and liabilities that had been recorded by ETE as reflected below.
The following table summarizes the assets acquired and liabilities assumed as of the respective acquisition dates:
 
Sunoco, Inc.(1)
 
Southern Union(2)
Current assets$7,312
 $556
Property, plant and equipment6,686
 6,242
Goodwill2,641
 2,497
Intangible assets1,361
 55
Investments in unconsolidated affiliates240
 2,023
Note receivable821
 —
Other assets128
 163
 19,189
 11,536
    
Current liabilities4,424
 1,348
Long-term debt obligations, less current maturities2,879
 3,120
Deferred income taxes1,762
 1,419
Other non-current liabilities769
 284
Noncontrolling interest3,580
 —
 13,414
 6,171
Total consideration5,775
 5,365
Cash received2,714
 37
Total consideration, net of cash received$3,061
 $5,328
 December 31, 2017 December 31, 2016
 
Notional
Volume
 Maturity 
Notional
Volume
 Maturity
Mark-to-Market Derivatives       
(Trading)       
Natural Gas (BBtu):       
Fixed Swaps/Futures1,078
 2018 (683) 2017
Basis Swaps IFERC/NYMEX (1)
48,510
 2018-2020 2,243
 2017
Options – Puts13,000
 2018 —
 —
Power (Megawatt):       
Forwards435,960
 2018-2019 391,880
 2017 - 2018
Futures(25,760) 2018 109,564
 2017 - 2018
Options — Puts(153,600) 2018 (50,400) 2017
Options — Calls137,600
 2018 186,400
 2017
Crude (MBbls) – Futures—
 — (617) 2017
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX4,650
 2018-2020 10,750
 2017 - 2018
Swing Swaps IFERC87,253
 2018-2019 (5,663) 2017
Fixed Swaps/Futures(4,390) 2018-2019 (52,653) 2017 - 2019
Forward Physical Contracts(145,105) 2018-2020 (22,492) 2017
Natural Gas Liquid (MBbls) – Forwards/Swaps6,744
 2018-2019 (5,787) 2017
Refined Products (MBbls) – Futures(3,901) 2018-2019 (3,144) 2017
Corn (Bushels) – Futures1,870,000
 2018 1,580,000
 2017
Fair Value Hedging Derivatives       
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX(39,770) 2018 (36,370) 2017
Fixed Swaps/Futures(39,770) 2018 (36,370) 2017
Hedged Item — Inventory39,770
 2018 36,370
 2017
(1) 
Includes aggregate amounts recorded with respectfor open positions related to Sunoco Logistics.

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(2)
Includes ETP’s acquisition of Citrus.Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
The fair valuesInterest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Asrate on a result of the ETP Holdco Transaction, we recognized $38 million of merger-related costs during the year ended December 31, 2012 related to Southern Union. Southern Union’s revenue included in our consolidated statement of operations was approximately $1.26 billion since the acquisition date to December 31, 2012. Southern Union’s net income included in our consolidated statement of operations was approximately $39 million since the acquisition date to December 31, 2012.
Propane Operations
On January 12, 2012, we contributed our propane operations, consisting of HOLP and Titan (collectively, the “Propane Business”) to AmeriGas. We received approximately $1.46 billion in cash and approximately 29.6 million AmeriGas common units. AmeriGas assumed approximately $71 million of existing HOLP debt. In connection with the closing of this transaction, we entered into a support agreement with AmeriGas pursuant to which we are obligated to provide contingent, residual support of $1.50 billion of intercompany indebtedness owed by AmeriGas to a finance subsidiary that in turn supports the repayment of $1.50 billion of senior notes issued by this AmeriGas finance subsidiary to finance the cash portion of the purchase price.our anticipated debt issuances.
Our consolidated financial statements did not reflect the Propane Business as discontinued operations due to our continuing involvement in this business through our investment in AmeriGas that was transferred as consideration for the transaction.
In June 2012, we sold the remainder of our retail propane operations, consisting of our cylinder exchange business, to a third party. In connection with the contribution agreement with AmeriGas, certain excess sales proceeds from the sale of the cylinder exchange business were remitted to AmeriGas, and we received net proceeds of approximately $43 million.
Sale of Canyon
In October 2012, we sold Canyon for approximately $207 million.  The results of continuing operations of Canyon have been reclassified to loss from discontinued operations and the prior year amounts have been restated to present Canyon’s operations as discontinued operations. A write down of the carrying amounts of the Canyon assets to their fair values was recorded for approximately $132 million during the year ended December 31, 2012.  Canyon was previously included in our midstream segment.
Pro Forma Results of Operations
The following unaudited pro forma consolidated resultstable summarizes our interest rate swaps outstanding, none of operationswhich are designated as hedges for the year ended December 31, 2012 are presented as if the Sunoco Merger and the ETP Holdco Transaction had been completed on January 1, 2012:accounting purposes:
  Year Ended December 31, 2012
Revenues $39,136
Net income 1,133
Net income attributable to partners 788
Basic net income per Limited Partner unit $1.33
Diluted net income per Limited Partner unit $1.33
The pro forma consolidated results of operations include adjustments to:
include the results of Southern Union and Sunoco, Inc. beginning January 1, 2012;
include the incremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting;
include incremental interest expense related to the financing of ETP’s proportionate share of the purchase price; and
reflect noncontrolling interest related to ETE’s 60% interest in ETP Holdco during the periods.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

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4.ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
Regency
On April 30, 2013, Southern Union completed its contribution to Regency of all of the issued and outstanding membership interest in Southern Union Gathering Company, LLC, and its subsidiaries, including SUGS (see Note 3). The consideration paid by Regency in connection with this transaction included approximately 31.4 million Regency common units, approximately 6.3 million Regency Class F units, the distribution of $463 million in cash to Southern Union, net of closing adjustments, and the payment of $30 million in cash to a subsidiary of ETP. This direct investment in Regency common and Class F units received has been accounted for using the equity method.
The carrying amount of our investment in Regency was $1.34 billion and $1.41 billion as of December 31, 2014 and 2013, respectively, and was reflected in our all other segment.
Citrus
On March 26, 2012, ETE consummated the acquisition of Southern Union and, concurrently with the closing of the Southern Union acquisition, CrossCountry, a subsidiary of Southern Union that indirectly owned a 50% interest in Citrus, merged with a subsidiary of ETP and, in connection therewith, ETP paid approximately $1.9 billion in cash and issued $105 million of ETP Common Units (the “Citrus Acquisition”) to a subsidiary of ETE. As a result of the consummation of the Citrus Acquisition, ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of Kinder Morgan, Inc. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula.
We recorded our investment in Citrus at $2.0 billion, which exceeded our proportionate share of Citrus’ equity by $1.03 billion, all of which is treated as equity method goodwill due to the application of regulatory accounting. The carrying amount of our investment in Citrus was $1.82 billion and $1.89 billion as of December 31, 2014 and 2013, respectively, and was reflected in our interstate transportation and storage segment.
AmeriGas
As discussed in Note 3, on January 12, 2012, we received approximately 29.6 million AmeriGas common units in connection with the contribution of our propane operations. In the year ended 2013, we sold 7.5 million AmeriGas common units for net proceeds of $346 million, and in the year ended 2014 we sold approximately 18.9 million AmeriGas common units for net proceeds of $814 million. Net proceeds from these sales were used to repay borrowings under the ETP Credit Facility and general partnership purposes. Subsequent to the sales, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company.
FEP
We have a 50% interest in FEP, a 50/50 joint venture with KMP. FEP owns the Fayetteville Express pipeline, an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. The carrying amount of our investment in FEP was $130 million and $144 million as of December 31, 2014 and 2013, respectively, and was reflected in our interstate transportation and storage segment.

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Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, FEP, AmeriGas, Citrus and Regency (on a 100% basis) for all periods presented:
 December 31,
 2014 2013
Current assets$1,514
 $1,372
Property, plant and equipment, net16,967
 12,320
Other assets9,708
 6,478
Total assets$28,189
 $20,170
    
Current liabilities$2,324
 $1,455
Non-current liabilities13,206
 10,286
Equity12,659
 8,429
Total liabilities and equity$28,189
 $20,170
 Years Ended December 31,
 2014 2013 2012
Revenue$9,467
 $6,806
 $4,057
Operating income841
 1,043
 635
Net income279
 574
 338
In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.

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5.NET INCOME PER LIMITED PARTNER UNIT:
A reconciliation of income from continuing operations and weighted average units used in computing basic and diluted income from continuing operations per unit is as follows:
 Years Ended December 31,
 2014 2013 2012
Income from continuing operations$1,489
 $735
 $1,757
Less: Income from continuing operations attributable to noncontrolling interest217
 296
 62
Income from continuing operations, net of noncontrolling interest1,272
 439
 1,695
General Partner’s interest in income from continuing operations513
 505
 463
Class H Unitholder’s interest in income from continuing operations217
 —
 —
Common Unitholders’ interest in income (loss) from continuing operations542
 (66) 1,232
Additional earnings allocated (to) from General Partner(4) (2) 1
Distributions on employee unit awards, net of allocation to General Partner(13) (10) (9)
Income (loss) from continuing operations available to Common Unitholders$525
 $(78) $1,224
Weighted average Common Units – basic331.5
 343.4
 248.3
Basic income (loss) from continuing operations per Common Unit$1.58
 $(0.23) $4.93
Dilutive effect of unvested Unit Awards1.3
 —
 0.7
Weighted average Common Units, assuming dilutive effect of unvested Unit Awards332.8
 343.4
 249.0
Diluted income (loss) from continuing operations per Common Unit$1.58
 $(0.23) $4.91
Basic income (loss) from discontinued operations per Common Unit$0.19
 $0.05
 $(0.50)
Diluted income (loss) from discontinued operations per Common Unit$0.19
 $0.05
 $(0.50)
6.DEBT OBLIGATIONS:
Our debt obligations consist of the following:
 December 31,
 2014 2013
ETP Debt   
8.5% Senior Notes due April 15, 2014$—
 $292
5.95% Senior Notes due February 1, 2015750
 750
6.125% Senior Notes due February 15, 2017400
 400
6.7% Senior Notes due July 1, 2018600
 600
9.7% Senior Notes due March 15, 2019400
 400
9.0% Senior Notes due April 15, 2019450
 450
4.15% Senior Notes due October 1, 2020700
 700
4.65% Senior Notes due June 1, 2021800
 800
5.20% Senior Notes due February 1, 20221,000
 1,000
3.60% Senior Notes due February 1, 2023800
 800
4.9% Senior Notes due February 1, 2024350
 350
7.6% Senior Notes due February 1, 2024277
 277
8.25% Senior Notes due November 15, 2029267
 267
6.625% Senior Notes due October 15, 2036400
 400
7.5% Senior Notes due July 1, 2038550
 550

S - 38

6.05% Senior Notes due June 1, 2041700
 700
6.50% Senior Notes due February 1, 20421,000
 1,000
5.15% Senior Notes due February 1, 2043450
 450
5.95% Senior Notes due October 1, 2043450
 450
Floating Rate Junior Subordinated Notes due November 1, 2066546
 546
ETP $2.5 billion Revolving Credit Facility due October 27, 2019570
 65
Unamortized premiums, discounts and fair value adjustments, net(1) (34)
 11,459
 11,213
    
Transwestern Debt   
5.39% Senior Notes due November 17, 2014—
 88
5.54% Senior Notes due November 17, 2016125
 125
5.64% Senior Notes due May 24, 201782
 82
5.36% Senior Notes due December 9, 2020175
 175
5.89% Senior Notes due May 24, 2022150
 150
5.66% Senior Notes due December 9, 2024175
 175
6.16% Senior Notes due May 24, 203775
 75
Unamortized premiums, discounts and fair value adjustments, net(1) (1)
 781
 869
    
Panhandle Debt(1)
   
6.20% Senior Notes due November 1, 2017300
 300
7.00% Senior Notes due June 15, 2018400
 400
8.125% Senior Notes due June 1, 2019150
 150
7.60% Senior Notes due February 1, 202482
 82
7.00% Senior Notes due July 15, 202966
 66
8.25% Senior Notes due November 14, 202933
 33
Floating Rate Junior Subordinated Notes due November 1, 206654
 54
Unamortized premiums, discounts and fair value adjustments, net99
 155
 1,184
 1,240
    
Sunoco, Inc. Debt   
4.875% Senior Notes due October 15, 2014—
 250
9.625% Senior Notes due April 15, 2015250
 250
5.75% Senior Notes due January 15, 2017400
 400
9.00% Debentures due November 1, 202465
 65
Unamortized premiums, discounts and fair value adjustments, net35
 70
 750
 1,035
    
Sunoco Logistics Debt   
8.75% Senior Notes due February 15, 2014(2)
—
 175
6.125% Senior Notes due May 15, 2016175
 175
5.50% Senior Notes due February 15, 2020250
 250
4.65% Senior Notes due February 15, 2022300
 300
3.45% Senior Notes due January 15, 2023350
 350
4.25% Senior Notes due April 1, 2024500
 —
6.85% Senior Notes due February 15, 2040250
 250
6.10% Senior Notes due February 15, 2042300
 300
4.95% Senior Notes due January 15, 2043350
 350
5.30% Senior Notes due April 1, 2044700
 —

S - 39

5.35% Senior Notes due May 15, 2045800
 —
Sunoco Logistics $35 million Revolving Credit Facility due April 30, 2015(3)
35
 35
Sunoco Logistics $1.50 billion Revolving Credit Facility due November 19, 2018150
 200
Unamortized premiums, discounts and fair value adjustments, net100
 118
 4,260
 2,503
    
Sunoco LP Debt   
Sunoco LP $1.25 billion Revolving Credit Facility due September 25, 2019683
 —
 683
 —
    
Other223
 228
 19,340
 17,088
Less: current maturities1,008
 637
 $18,332
 $16,451
      Notional Amount Outstanding
Entity Term 
Type(1)
 December 31, 2017 December 31, 2016
ETP 
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
ETP 
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
ETP 
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
ETP 
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
ETP December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
ETP March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
(1) 
In connection with the Panhandle Merger, Southern Union’s debt obligations were assumed by Panhandle.Floating rates are based on 3-month LIBOR.
(2) 
Sunoco Logistics’ 8.75% senior notes due February 15, 2014 were classifiedRepresents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as long-term debt as Sunoco Logistics repaid these notes in February 2014 with borrowings under its $1.50 billion credit facility due November 2018.the effective date.
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies, and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
 Fair Value of Derivative Instruments
 Asset Derivatives Liability Derivatives
 December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives designated as hedging instruments:       
Commodity derivatives (margin deposits)$14
 $—
 $(2) $(4)
 14
 —
 (2) (4)
Derivatives not designated as hedging instruments:       
Commodity derivatives (margin deposits)262
 338
 (281) (416)
Commodity derivatives45
 25
 (58) (58)
Interest rate derivatives—
 —
 (219) (193)
Embedded derivatives in ETP Convertible Preferred Units—
 —
 —
 (1)
 307
 363
 (558) (668)
Total derivatives$321
 $363
 $(560) $(672)
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
    Asset Derivatives Liability Derivatives
  Balance Sheet Location December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives without offsetting agreements Derivative assets (liabilities) $—
 $—
 $(219) $(194)
Derivatives in offsetting agreements:        
OTC contracts Derivative assets (liabilities) 45
 25
 (58) (58)
Broker cleared derivative contracts Other current assets (liabilities) 276
 338
 (283) (420)
  321
 363
 (560) (672)
Offsetting agreements:        
Counterparty netting Derivative assets (liabilities) (21) (4) 21
 4
Counterparty netting Other current assets (liabilities) (263) (338) 263
 338
Total net derivatives $37
 $21
 $(276) $(330)
We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to our derivative financial instruments:
 
Location of Gain/(Loss)
Recognized in
Income on Derivatives
 
Amount of Gain/(Loss) Recognized in Income
Representing Hedge Ineffectiveness and
Amount Excluded from the Assessment of
Effectiveness
 Years Ended December 31,
 2017 2016 2015
Derivatives in fair value hedging relationships (including hedged item):       
Commodity derivativesCost of products sold $26
 $14
 $21
Total  $26
 $14
 $21
 Location of Gain/(Loss) Recognized in Income on Derivatives 
Amount of Gain/(Loss) Recognized
in Income on Derivatives
  Years Ended December 31,
  2017 2016 2015
Derivatives not designated as hedging instruments:       
Commodity derivatives – TradingCost of products sold $31
 $(35) $(11)
Commodity derivatives – Non-tradingCost of products sold 5
 (177) 15
Interest rate derivativesLosses on interest rate derivatives (37) (12) (18)
Embedded derivativesOther, net 1
 4
 12
Total  $—
 $(220) $(2)

13.RETIREMENT BENEFITS:
Savings and Profit Sharing Plans
We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETP, Sunoco LP and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $38 million, $44 million and $40 million to the 401(k) savings plan for the years ended December 31, 2017, 2016, and 2015, respectively.
Pension and Other Postretirement Benefit Plans
Panhandle
Postretirement benefits expense for the years ended December 31, 2017, 2016, and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.
Sunoco, Inc.
Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.
Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.

The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
 December 31, 2017 December 31, 2016
 Pension Benefits   Pension Benefits  
 Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Change in benefit obligation:           
Benefit obligation at beginning of period$18
 $51
 $166
 $20
 $57
 $181
Interest cost1
 1
 4
 1
 2
 4
Amendments—
 —
 7
 —
 —
 —
Benefits paid, net(2) (6) (20) (1) (7) (21)
Actuarial (gain) loss and other2
 1
 (1) (2) (1) 2
Settlements(18) —
 —
 —
 —
 —
Benefit obligation at end of period$1
 $47
 $156
 $18
 $51
 $166
            
Change in plan assets:           
Fair value of plan assets at beginning of period$12
 $—
 $256
 $15
 $—
 $261
Return on plan assets and other3
 —
 11
 (2) —
 6
Employer contributions6
 —
 10
 —
 —
 10
Benefits paid, net(2) —
 (20) (1) —
 (21)
Settlements(18) —
 —
 —
 —
 —
Fair value of plan assets at end of period$1
 $—
 $257
 $12
 $—
 $256
            
Amount underfunded (overfunded) at end of period$—
 $47
 $(101) $6
 $51
 $(90)
            
Amounts recognized in the consolidated balance sheets consist of:           
Non-current assets$—
 $—
 $127
 $—
 $—
 $114
Current liabilities—
 (8) (2) —
 (7) (2)
Non-current liabilities—
 (39) (24) (6) (44) (23)
 $—
 $(47) $101
 $(6) $(51) $89
            
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:           
Net actuarial gain$—
 $5
 $(18) $—
 $—
 $(13)
Prior service cost—
 —
 21
 —
 —
 15
 $—
 $5
 $3
 $—
 $—
 $2

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
 December 31, 2017 December 31, 2016
 Pension Benefits   Pension Benefits  
 Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Projected benefit obligation$1
 $47
 N/A
 $18
 $51
 N/A
Accumulated benefit obligation1
 47
 $156
 18
 51
 $166
Fair value of plan assets1
 —
 257
 12
 —
 256
Components of Net Periodic Benefit Cost
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Net Periodic Benefit Cost:       
Interest cost$2
 $4
 $3
 $4
Expected return on plan assets—
 (9) (1) (8)
Prior service cost amortization—
 2
 —
 1
Net periodic benefit cost$2
 $(3) $2
 $(3)
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.27% 2.34% 3.65% 2.34%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.52% 3.10% 3.60% 3.06%
Expected return on assets:       
Tax exempt accounts3.50% 7.00% 3.50% 7.00%
Taxable accountsN/A
 4.50% N/A
 4.50%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest

rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:
 December 31,
 2017 2016
Health care cost trend rate7.20% 6.73%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)4.99% 4.96%
Year that the rate reaches the ultimate trend rate2023
 2021
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%. 
The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.
The fair value of the pension plan assets by asset category at the dates indicated is as follows:
    Fair Value Measurements at December 31, 2017
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Mutual funds (1)
 $1
 $1
 $—
 $—
Total $1
 $1
 $—
 $—
(3)(1)
Comprised of 100% equities as of December 31, 2017.
    Fair Value Measurements at December 31, 2016
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Mutual funds (1)
 $12
 $12
 $—
 $—
Total $12
 $12
 $—
 $—
(1) 
The Sunoco Logistics $35 million credit facility outstanding amounts were classifiedComprised of 100% equities as long-term debtof December 31, 2016.

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
    Fair Value Measurements at December 31, 2017
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $33
 $33
 $—
 $—
Mutual funds (1)
 154
 154
 —
 —
Fixed income securities 70
 —
 70
 —
Total $257
 $187
 $70
 $—
(1)
Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% cash as Sunoco Logistics has the abilityof December 31, 2017.
    Fair Value Measurements at December 31, 2016
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $23
 $23
 $—
 $—
Mutual funds (1)
 142
 142
 —
 —
Fixed income securities 91
 —
 91
 —
Total $256
 $165
 $91
 $—
(1)
Primarily comprised of approximately 31% equities, 66% fixed income securities and intent to refinance such borrowings on a long-term basis.3% cash as of December 31, 2016.
The following table reflectsLevel 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  
Contributions
We expect to contribute $8 million to pension plans and $10 million to other postretirement plans in 2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future maturities of long-term debt forservice, as appropriate, in each of the next five years and thereafter. These amounts exclude $232 million in unamortized net premiums and fair value adjustments:the aggregate for the five years thereafter are shown in the table below:
2015 $1,050
2016 314
2017 1,228
2018 1,155
2019 2,259
Thereafter 13,102
Total $19,108
Years 
Pension Benefits - Unfunded Plans (1)
 Other Postretirement Benefits (Gross, Before Medicare Part D)
2018 $8
 $24
2019 6
 23
2020 6
 21
2021 5
 19
2022 4
 17
2023 – 2027 15
 37
(1)     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

14.RELATED PARTY TRANSACTIONS:
In June 2017, ETP acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8.
ETE previously paid ETP to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016.
In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million and $290 million during the years ended December 31, 2017, 2016 and 2015, respectively.
15.REPORTABLE SEGMENTS:
Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
ETP as Co-Obligorcompleted its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.
The Investment in Sunoco LP segment reflects the results of Sunoco Inc. DebtLP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.
We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.
Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

Eliminations in the tables below include the following:
MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above.
 Years Ended December 31,
 2017 2016 2015
Revenues:     
Investment in ETP:     
Revenues from external customers$28,613
 $21,618
 $34,156
Intersegment revenues441
 209
 136
 29,054
 21,827
 34,292
Investment in Sunoco LP:     
Revenues from external customers11,713
 9,977
 12,419
Intersegment revenues10
 9
 11
 11,723
 9,986
 12,430
Investment in Lake Charles LNG:     
Revenues from external customers197
 197
 216
 

 

 

Adjustments and Eliminations:(451) (218) (10,842)
Total revenues$40,523
 $31,792
 $36,096
      
Costs of products sold:     
Investment in ETP$20,801
 $15,080
 $26,714
Investment in Sunoco LP10,615
 8,830
 11,450
Adjustments and Eliminations(450) (217) (9,496)
Total costs of products sold$30,966
 $23,693
 $28,668
      
Depreciation, depletion and amortization:     
Investment in ETP$2,332
 $1,986
 $1,929
Investment in Sunoco LP169
 176
 150
Investment in Lake Charles LNG39
 39
 39
Corporate and Other14
 15
 17
Adjustments and Eliminations—
 —
 (184)
Total depreciation, depletion and amortization$2,554
 $2,216
 $1,951
 Years Ended December 31,
 2017 2016 2015
Equity in earnings of unconsolidated affiliates:     
Investment in ETP$156
 $59
 $469
Adjustments and Eliminations(12) 211
 (193)
Total equity in earnings of unconsolidated affiliates$144
 $270
 $276

 Years Ended December 31,
 2017 2016 2015
Segment Adjusted EBITDA:     
Investment in ETP$6,712
 $5,733
 $5,517
Investment in Sunoco LP732
 665
 719
Investment in Lake Charles LNG175
 179
 196
Corporate and Other(31) (170) (104)
Adjustments and Eliminations(268) (272) (590)
Total Segment Adjusted EBITDA7,320
 6,135
 5,738
Depreciation, depletion and amortization(2,554) (2,216) (1,951)
Interest expense, net of interest capitalized(1,922) (1,804) (1,622)
Gains on acquisitions—
 83
 —
Impairment of investments in unconsolidated affiliates(313) (308) —
Impairment losses(1,039) (1,040) (339)
Losses on interest rate derivatives(37) (12) (18)
Non-cash unit-based compensation expense(99) (70) (91)
Unrealized gains (losses) on commodity risk management activities59
 (136) (65)
Losses on extinguishments of debt(89) —
 (43)
Inventory valuation adjustments24
 97
 (67)
Adjusted EBITDA related to discontinued operations(223) (199) (228)
Adjusted EBITDA related to unconsolidated affiliates(716) (675) (713)
Equity in earnings of unconsolidated affiliates144
 270
 276
Other, net155
 79
 23
Income from continuing operations before income tax benefit$710
 $204
 $900
Income tax benefit from continuing operations(1,833) (258) (123)
Income from continuing operations2,543
 462
 1,023
Income (loss) from discontinued operations, net of tax(177) (462) 38
Net income$2,366
 $—
 $1,061
 December 31,
 2017 2016 2015
Total assets:     
Investment in ETP$77,965
 $70,105
 $65,128
Investment in Sunoco LP8,344
 8,701
 8,842
Investment in Lake Charles LNG1,646
 1,508
 1,369
Corporate and Other598
 711
 638
Adjustments and Eliminations(2,307) (2,100) (4,833)
Total$86,246
 $78,925
 $71,144

 Years Ended December 31,
 2017 2016 2015
Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):     
Investment in ETP$5,901
 $5,810
 $8,167
Investment in Sunoco LP103
 119
 178
Investment in Lake Charles LNG2
 —
 1
Adjustments and Eliminations—
 —
 (123)
Total$6,006
 $5,929
 $8,223
 December 31,
 2017 2016 2015
Advances to and investments in affiliates:     
Investment in ETP$3,816
 $4,280
 $5,003
Adjustments and Eliminations(1,111) (1,240) (1,541)
Total$2,705
 $3,040
 $3,462
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP.
Investment in ETP
 Years Ended December 31,
 2017 2016 2015
Intrastate Transportation and Storage$2,891
 $2,155
 $1,912
Interstate Transportation and Storage915
 946
 1,008
Midstream2,510
 2,342
 2,607
NGL and refined products transportation and services8,326
 5,973
 4,569
Crude oil transportation and services11,672
 7,539
 8,980
All Other2,740
 2,872
 15,216
Total revenues29,054
 21,827
 34,292
Less: Intersegment revenues441
 209
 136
Revenues from external customers$28,613
 $21,618
 $34,156
Investment in Sunoco LP
 Years Ended December 31,
 2017 2016 2015
Retail operations$2,263
 $1,991
 $2,226
Wholesale operations9,460
 7,995
 10,204
Total revenues11,723
 9,986
 12,430
Less: Intersegment revenues10
 9
 11
Revenues from external customers$11,713
 $9,977
 $12,419
Investment in Lake Charles LNG
Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 2015, respectively, were related to LNG terminalling.

16.QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.
 Quarters Ended  
 March 31* June 30* September 30* December 31 Total Year
2017:         
Revenues$9,660
 $9,427
 $9,984
 $11,452
 $40,523
Operating income (loss)758
 746
 924
 285
 2,713
Net income (loss)319
 121
 758
 1,168
 2,366
Limited Partners’ interest in net income232
 204
 240
 239
 915
Basic net income per limited partner unit$0.22
 $0.18
 $0.22
 $0.22
 $0.85
Diluted net income per limited partner unit$0.21
 $0.18
 $0.22
 $0.22
 $0.83
 Quarters Ended  
 March 31* June 30* September 30* December 31* Total Year*
2016:         
Revenues$6,447
 $7,866
 $8,156
 $9,323
 $31,792
Operating income680
 814
 624
 (275) 1,843
Net income (loss)320
 417
 (3) (734) —
Limited Partners’ interest in net income311
 239
 207
 226
 983
Basic net income per limited partner unit$0.30
 $0.23
 $0.20
 $0.22
 $0.94
Diluted net income per limited partner unit$0.30
 $0.23
 $0.19
 $0.21
 $0.92
* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.
The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to ETP’s interstate transportation and storage operations, NGL and refined products operations and other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its interstate transportation and storage operations.

17.SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:
Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:
BALANCE SHEETS
 December 31,
 2017 2016
ASSETS   
CURRENT ASSETS:   
Cash and cash equivalents$1
 $2
Accounts receivable from related companies65
 55
Other current assets1
 —
Total current assets67
 57
PROPERTY, PLANT AND EQUIPMENT, net27
 36
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES6,082
 5,088
INTANGIBLE ASSETS, net—
 1
GOODWILL9
 9
OTHER NON-CURRENT ASSETS, net8
 10
Total assets$6,193
 $5,201
LIABILITIES AND PARTNERS’ CAPITAL   
CURRENT LIABILITIES:   
Accounts payable$—
 $1
Accounts payable to related companies—
 22
Interest payable66
 66
Accrued and other current liabilities4
 3
Total current liabilities70
 92
LONG-TERM DEBT, less current maturities6,700
 6,358
NOTE PAYABLE TO AFFILIATE617
 443
OTHER NON-CURRENT LIABILITIES2
 2
    
COMMITMENTS AND CONTINGENCIES
 
    
PARTNERS’ DEFICIT:   
General Partner(3) (3)
Limited Partners:   
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)(1,643) (1,871)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)450
 180
Total partners’ deficit(1,196) (1,694)
Total liabilities and partners’ deficit$6,193
 $5,201


STATEMENTS OF OPERATIONS
 Years Ended December 31,
 2017 2016 2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES$(31) $(185) $(112)
OTHER INCOME (EXPENSE):     
Interest expense, net of interest capitalized(347) (327) (294)
Equity in earnings of unconsolidated affiliates1,381
 1,511
 1,601
Loss on extinguishment of debt(47) —
 —
Other, net(2) (4) (5)
INCOME BEFORE INCOME TAXES954
 995
 1,190
Income tax expense—
 —
 1
NET INCOME954
 995
 1,189
General Partner’s interest in net income2
 3
 3
Convertible Unitholders’ interest in income37
 9
 —
Class D Unitholder’s interest in net income—
 —
 3
Limited Partners’ interest in net income$915
 $983
 $1,183


STATEMENTS OF CASH FLOWS
 Years Ended December 31,
 2017 2016 2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES$831
 $918
 $1,103
CASH FLOWS FROM INVESTING ACTIVITIES:     
Cash paid for Bakken Pipeline Transaction—
 —
 (817)
Contributions to unconsolidated affiliates(861) (70) —
Capital expenditures(1) (16) (19)
Contributions in aid of construction costs7
 —
 —
Net cash used in investing activities(855) (86) (836)
CASH FLOWS FROM FINANCING ACTIVITIES:     
Proceeds from borrowings2,219
 225
 3,672
Principal payments on debt(1,881) (210) (1,985)
Distributions to partners(1,010) (1,022) (1,090)
Proceeds from affiliate174
 176
 210
Common Units issued for cash568
 —
 —
Units repurchased under buyback program—
 —
 (1,064)
Debt issuance costs(47) —
 (11)
Net cash provided by (used in) financing activities23
 (831) (268)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(1) 1
 (1)
CASH AND CASH EQUIVALENTS, beginning of period2
 1
 2
CASH AND CASH EQUIVALENTS, end of period$1
 $2
 $1


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS
OF CERTAIN SUBSIDIARIES INCLUDED PURSUANT
TO RULE 3-16 OF REGULATION S-X
Page
1. Energy Transfer Partners, L.P. Financial StatementsS - 2


1.ENERGY TRANSFER PARTNERS, L.P. FINANCIAL STATEMENTS


INDEX TO FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting FirmS - 3
Consolidated Balance Sheets – December 31, 2017 and 2016S - 4
Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 and 2015S - 6
Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 and 2015S - 7
Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 and 2015S - 8
Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 and 2015S - 10
Notes to Consolidated Financial StatementsS - 12

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors of Energy Transfer Partners, L.L.C. and
Unitholders of Energy Transfer Partners, L.P.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 2018 (not separately included herein) expressed an unqualified opinion thereon.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2004.

Dallas, Texas
February 23, 2018


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
ASSETS   
Current assets:   
Cash and cash equivalents$306
 $360
Accounts receivable, net3,946
 3,002
Accounts receivable from related companies318
 209
Inventories1,589
 1,626
Income taxes receivable135
 128
Derivative assets24
 20
Other current assets210
 298
Total current assets6,528
 5,643
    
Property, plant and equipment67,699
 58,220
Accumulated depreciation and depletion(9,262) (7,303)
 58,437
 50,917
    
Advances to and investments in unconsolidated affiliates3,816
 4,280
Other non-current assets, net758
 672
Intangible assets, net5,311
 4,696
Goodwill3,115
 3,897
Total assets$77,965
 $70,105
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable$4,126
 $2,900
Accounts payable to related companies209
 43
Derivative liabilities109
 166
Accrued and other current liabilities2,143
 1,905
Current maturities of long-term debt407
 1,189
Total current liabilities6,994
 6,203
    
Long-term debt, less current maturities32,687
 31,741
Long-term notes payable – related company—
 250
Non-current derivative liabilities145
 76
Deferred income taxes2,883
 4,394
Other non-current liabilities1,084
 952
    
Commitments and contingencies
 

Legacy ETP Preferred Units—
 33
Redeemable noncontrolling interests21
 15
    
Equity:   
Series A Preferred Units (950,000 units authorized, issued and outstanding as of December 31, 2017)944
 —
Series B Preferred Units (550,000 units authorized, issued and outstanding as of December 31, 2017)547
 —
Limited Partners:   
Common Unitholders (1,164,112,575 and 794,803,854 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)26,531
 14,925
Class E Unitholder (8,853,832 units authorized, issued and outstanding – held by subsidiary)—
 —
Class G Unitholder (90,706,000 units authorized, issued and outstanding – held by subsidiary)—
 —
Class H Unitholder (81,001,069 units authorized, issued and outstanding as of December 31, 2016)—
 3,480
Class I Unitholder (100 units authorized, issued and outstanding)—
 2
Class K Unitholders (101,525,429 units authorized, issued and outstanding – held by subsidiaries)—
 —
General Partner244
 206
Accumulated other comprehensive income3
 8
Total partners’ capital28,269
 18,621
Noncontrolling interest5,882
 7,820
Total equity34,151
 26,441
Total liabilities and equity$77,965
 $70,105
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
 Years Ended December 31,
 2017 2016* 2015*
REVENUES:     
Natural gas sales$4,172
 $3,619
 $3,671
NGL sales6,972
 4,841
 3,936
Crude sales10,184
 6,766
 8,378
Gathering, transportation and other fees4,265
 4,003
 3,997
Refined product sales (see Note 3)1,515
 1,047
 9,958
Other (see Note 3)1,946
 1,551
 4,352
Total revenues29,054
 21,827
 34,292
COSTS AND EXPENSES:     
Cost of products sold (see Note 3)20,801
 15,080
 26,714
Operating expenses (see Note 3)2,170
 1,839
 2,608
Depreciation, depletion and amortization2,332
 1,986
 1,929
Selling, general and administrative (see Note 3)434
 348
 475
Impairment losses920
 813
 339
Total costs and expenses26,657
 20,066
 32,065
OPERATING INCOME2,397
 1,761
 2,227
OTHER INCOME (EXPENSE):     
Interest expense, net(1,365) (1,317) (1,291)
Equity in earnings from unconsolidated affiliates156
 59
 469
Impairment of investments in unconsolidated affiliates(313) (308) —
Gains on acquisitions—
 83
 —
Losses on extinguishments of debt(42) —
 (43)
Losses on interest rate derivatives(37) (12) (18)
Other, net209
 131
 22
INCOME BEFORE INCOME TAX BENEFIT1,005
 397
 1,366
Income tax benefit(1,496) (186) (123)
NET INCOME2,501
 583
 1,489
Less: Net income attributable to noncontrolling interest420
 295
 134
Less: Net loss attributable to predecessor—
 —
 (34)
NET INCOME ATTRIBUTABLE TO PARTNERS2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)$986
 $(1,019) $(27)
NET INCOME (LOSS) PER COMMON UNIT:     
Basic$0.94
 $(1.38) $(0.07)
Diluted$0.93
 $(1.38) $(0.08)
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
Net income$2,501
 $583
 $1,489
Other comprehensive income (loss), net of tax:     
Change in value of available-for-sale securities6
 2
 (3)
Actuarial gain (loss) relating to pension and other postretirement benefits(12) (1) 65
Foreign currency translation adjustment—
 (1) (1)
Change in other comprehensive income (loss) from unconsolidated affiliates1
 4
 (1)
 (5) 4
 60
Comprehensive income2,496
 587
 1,549
Less: Comprehensive income attributable to noncontrolling interest420
 295
 134
Less: Comprehensive loss attributable to predecessor—
 —
 (34)
Comprehensive income attributable to partners$2,076
 $292
 $1,449
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
     Limited Partners          
 Series A Preferred Units Series B Preferred Units Common Unit holders Class H Units Class I Units General
Partner		 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-controlling
Interest
 Predecessor Equity Total
Balance, December 31, 2014*$—
 $—
 $10,427
 $1,512
 $—
 $184
 $(56) $5,143
 $8,088
 $25,298
Distributions to partners—
 —
 (1,863) (247) (80) (944) —
 —
 —
 (3,134)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (338) —
 (338)
Units issued for cash—
 —
 1,428
 —
 —
 —
 —
 —
 —
 1,428
Subsidiary units issued for cash—
 —
 298
 —
 —
 2
 —
 1,219
 —
 1,519
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 875
 —
 875
Bakken Pipeline Transaction—
 —
 (999) 1,946
 —
 —
 —
 72
 —
 1,019
Sunoco LP Exchange Transaction—
 —
 (52) —
 —
 —
 —
 (940) —
 (992)
Susser Exchange Transaction—
 —
 (68) —
 —
 —
 —
 —
 —
 (68)
Acquisition and disposition of noncontrolling interest—
 —
 (26) —
 —
 —
 —
 (39) —
 (65)
Predecessor distributions to partners—
 —
 —
 —
 —
 —
 —
 —
 (202) (202)
Predecessor units issued for cash—
 —
 —
 —
 —
 —
 —
 —
 34
 34
Regency Merger—
 —
 7,890
 —
 —
 —
 —
 —
 (7,890) —
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 60
 —
 —
 60
Other, net—
 —
 23
 —
 —
 —
 —
 36
 4
 63
Net income (loss)—
 —
 (27) 258
 94
 1,064
 —
 134
 (34) 1,489
Balance, December 31, 2015*—
 —
 17,031
 3,469
 14
 306
 4
 6,162
 —
 26,986
Distributions to partners—
 —
 (2,134) (340) (20) (1,048) —
 —
 —
 (3,542)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (481) —
 (481)
Units issued for cash—
 —
 1,098
 —
 —
 —
 —
 —
 —
 1,098
Subsidiary units issued—
 —
 37
 —
 —
 —
 —
 1,351
 —
 1,388

Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 236
 —
 236
Sunoco, Inc. retail business to Sunoco LP transaction—
 —
 (405) —
 —
 —
 —
 —
 —
 (405)
PennTex Acquisition—
 —
 307
 —
 —
 —
 —
 236
 —
 543
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 4
 —
 —
 4
Other, net—
 —
 10
 —
 —
 —
 —
 21
 —
 31
Net income (loss)—
 —
 (1,019) 351
 8
 948
 —
 295
 —
 583
Balance, December 31, 2016*—
 —
 14,925
 3,480
 2
 206
 8
 7,820
 —
 26,441
Distributions to partners—
 —
 (2,419) (95) (2) (952) —
 —
 —
 (3,468)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (430) —
 (430)
Units issued for cash937
 542
 2,283
 —
 —
 —
 —
 —
 —
 3,762
Sunoco Logistics Merger—
 —
 9,416
 (3,478) —
 —
 —
 (5,938) —
 —
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 2,202
 —
 2,202
Sale of Bakken Pipeline interest—
 —
 1,260
 —
 —
 —
 —
 740
 —
 2,000
Sale of Rover Pipeline interest—
 —
 93
 —
 —
 —
 —
 1,385
 —
 1,478
Acquisition of PennTex noncontrolling interest—
 —
 (48) —
 —
 —
 —
 (232) —
 (280)
Other comprehensive loss, net of tax—
 —
 —
 —
 —
 —
 (5) —
 —
 (5)
Other, net—
 —
 35
 —
 —
 —
 —
 (85) —
 (50)
Net income7
 5
 986
 93
 —
 990
 —
 420
 —
 2,501
Balance, December 31, 2017$944
 $547
 $26,531
 $—
 $—
 $244
 $3
 $5,882
 $—
 $34,151
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
OPERATING ACTIVITIES:     
Net income$2,501
 $583
 $1,489
Reconciliation of net income to net cash provided by operating activities:     
Depreciation, depletion and amortization2,332
 1,986
 1,929
Deferred income taxes(1,531) (169) 202
Amortization included in interest expense2
 (20) (36)
Inventory valuation adjustments—
 —
 (58)
Unit-based compensation expense74
 80
 79
Impairment losses920
 813
 339
Gains on acquisitions—
 (83) —
Losses on extinguishments of debt42
 —
 43
Impairment of investments in unconsolidated affiliates313
 308
 —
Distributions on unvested awards(31) (25) (16)
Equity in earnings of unconsolidated affiliates(156) (59) (469)
Distributions from unconsolidated affiliates440
 406
 440
Other non-cash(261) (271) (22)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations(160) (246) (1,173)
Net cash provided by operating activities4,485
 3,303
 2,747
INVESTING ACTIVITIES:     
Cash proceeds from sale of Bakken Pipeline interest2,000
 —
 —
Cash proceeds from sale of Rover Pipeline interest1,478
 —
 —
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction—
 2,200
 —
Proceeds from Bakken Pipeline Transaction—
 —
 980
Proceeds from Susser Exchange Transaction—
 —
 967
Proceeds from sale of noncontrolling interest—
 —
 64
Cash paid for acquisition of PennTex noncontrolling interest(280) —
 —
Cash paid for Vitol Acquisition, net of cash received—
 (769) —
Cash paid for PennTex Acquisition, net of cash received—
 (299) —
Cash transferred to ETE in connection with the Sunoco LP Exchange—
 —
 (114)
Cash paid for acquisition of a noncontrolling interest—
 —
 (129)
Cash paid for all other acquisitions(264) (159) (675)
Capital expenditures, excluding allowance for equity funds used during construction(8,335) (7,550) (9,098)
Contributions in aid of construction costs24
 71
 80
Contributions to unconsolidated affiliates(268) (59) (45)
Distributions from unconsolidated affiliates in excess of cumulative earnings136
 135
 124
Proceeds from the sale of assets35
 25
 23
Change in restricted cash—
 14
 19
Other1
 1
 (16)
Net cash used in investing activities(5,473) (6,390) (7,820)
      

FINANCING ACTIVITIES:     
Proceeds from borrowings26,736
 19,916
 22,462
Repayments of long-term debt(26,494) (15,799) (17,843)
Cash (paid to) received from affiliate notes(255) 124
 233
Common Units issued for cash2,283
 1,098
 1,428
Preferred Units issued for cash1,479
 —
 —
Subsidiary units issued for cash—
 1,388
 1,519
Predecessor units issued for cash—
 —
 34
Capital contributions from noncontrolling interest1,214
 236
 841
Distributions to partners(3,468) (3,542) (3,134)
Predecessor distributions to partners—
 —
 (202)
Distributions to noncontrolling interest(430) (481) (338)
Redemption of Legacy ETP Preferred Units(53) —
 —
Debt issuance costs(83) (22) (63)
Other5
 2
 —
Net cash provided by financing activities934
 2,920
 4,937
Decrease in cash and cash equivalents(54) (167) (136)
Cash and cash equivalents, beginning of period360
 527
 663
Cash and cash equivalents, end of period$306
 $360
 $527
* As adjusted. See Note 2.




ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)

1.OPERATIONS AND BASIS OF PRESENTATION:
Organization. The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETP”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner.
In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled.
In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 millionSunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $715 million as of December 31, 2014.maintaining clarity, the following references are used herein:
ETP Senior Notes
The ETP senior notes were registered underReferences to “ETLP” refer to Energy Transfer, LP subsequent to the Securities Act of 1933 (as amended). The Partnership may redeem some or allclose of the ETP senior notes at any time, or from timemerger;
References to time, pursuant“Sunoco Logistics” refer to the termsentity named Sunoco Logistics Partners L.P. prior to the close of the indenturemerger; and related indenture supplements related
References to “ETP” refer to the ETP senior notes. The balance is payable upon maturity. Interest onconsolidated entity named Energy Transfer Partners, L.P. subsequent to the ETP senior notes is paid semi-annually.
The ETP senior notes are unsecured obligationsclose of the Partnership and the obligation of the Partnership to repay the ETP senior notes is not guaranteed by any of the Partnership’s subsidiaries. As a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.
Transwestern Senior Notes
The Transwestern notes are payable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.

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Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.26% at December 31, 2014.
Sunoco Logistics Senior Notes Offerings
In April 2014, Sunoco Logistics issued $300 million aggregate principal amount of 4.25% senior notes due April 2024 and $700 million aggregate principal amount of 5.30% senior notes due April 2044.
In November 2014, Sunoco Logistics issued $200 million aggregate principal amount of 4.25% senior notes due April 2024 and $800 million aggregate principal amount of 5.35% senior notes due May 2045. Sunoco Logistics used the net proceeds from the offerings to pay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes.
Credit Facilities
ETP Credit Facility
The ETP Credit Facility allows for borrowings of up to $2.5 billion and expires in October 2019. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt. We use the ETP Credit Facility to provide temporary financing for our growth projects, as well as for general partnership purposes. In February 2015, ETP amended its revolving credit facility to increase the capacity to $3.75 billion.
As of December 31, 2014, the ETP Credit Facility had $570 million outstanding, and the amount available for future borrowings was $1.81 billion after taking into account letters of credit of $121 million. The weighted average interest rate on the total amount outstanding as of December 31, 2014 was 1.66%.
Sunoco Logistics Credit Facilities
Sunoco Logistics maintains a $1.50 billion unsecured credit facility (the “Sunoco Logistics Credit Facility”) which matures in November 2018. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be extended to $2.25 billion under certain conditions.merger.
The Sunoco Logistics Credit Facility is availableMerger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to fund Sunoco Logistics’ working capital requirements,changing its name to finance acquisitions“Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and capital projects,reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to pay distributionsthe merger and for general partnership purposes. name changes).
The Sunoco Logistics Credit Facility bears interest at LIBORMerger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the Base Rate, each plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2014,periods prior to the Sunoco Logistics Credit Facility had $150 million of outstanding borrowings.
West Texas Gulf Pipe Line Company, a subsidiary ofMerger, the Sunoco Logistics maintainslimited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales.
The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.
The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.

The Partnership owns a $35 million revolving credit facility which expirescontrolling interest in April 2015. The facility is available to fund West Texas Gulf’s general corporate purposes including working capital and capital expenditures. At December 31, 2014, this credit facility had $35 million of outstanding borrowings.
Sunoco LP Credit Facility
In September 2014, Sunoco LP entered into a $1.25 billion revolving credit agreement (the “Sunoco LP Credit Facility”)Logistics Partners Operations L.P., which maturesowns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in September 2019. The Sunoco LP Credit Facility can be increased from time to time upon Sunoco LP’s written request, subject to certain conditions, up to an additional $250 million. Asaccordance with GAAP and include the accounts of December 31, 2014,all controlled subsidiaries after the Sunoco LP Credit Facility had $683 millionelimination of outstanding borrowings.
Covenants Related to Our Credit Agreements
Covenants Related to ETP
The agreements relatingall intercompany accounts and transactions. Certain prior year amounts have been conformed to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating fromcurrent year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.

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The credit agreement relating todate the ETP Credit Facility contains covenants that limit (subject tofinancial statements were issued.
For prior periods reported herein, certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
incur indebtedness;
grant liens;
enter into mergers;
dispose of assets;
make certain investments;
make Distributions (as defined in such credit agreement) during certain Defaults (as defined in such credit agreement) and during any Event of Default (as defined in such credit agreement);
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
engage in transactions with affiliates; and
enter into restrictive agreements.
The credit agreement relating to the ETP Credit Facility also contains a financial covenant that provides that the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1 as of the end of each quarter, with a permitted increase to 5.5 to 1 during a Specified Acquisition Period, as defined in the ETP Credit Facility.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.
In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Sunoco Logistics
Sunoco Logistics’ $1.50 billion credit facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants related to the operation and conduct of the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and its subsidiaries. The credit facility also limits Sunoco Logistics,their marketing affiliates. These reclassifications had no impact on a rolling four-quarter basis, to a maximumnet income or total consolidated debt to consolidated Adjusted EBITDA ratio, as defined in the underlying credit agreement, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total consolidated debt, excluding net unamortized

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fair value adjustments, to consolidated Adjusted EBITDA was 3.7 to 1 at December 31, 2014, as calculated in accordance with the credit agreements.equity.
The West Texas Gulf Pipeline Company’s $35 million credit facility limits West Texas Gulf, onPartnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a rolling four-quarter basis, to a minimum fixed charge coverage ratio of 1.00 to 1. In addition, the credit facility limits West Texas Gulf to a maximum leverage ratio of 2.00 to 1. West Texas Gulf’s fixed charge coverage ratio and leverage ratio were 1.67 to 1 and 0.85 to 1, respectively, at December 31, 2014.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility requires Sunoco LP to maintain a leverage ratio of not more than 5.50 to 1. The maximum leverage ratio is subject to upwards adjustment of not more than 6.00 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in an acquisition of assets, equity interests, operating lines or divisions by Sunoco LP, a subsidiary, an unrestricted subsidiary or apartnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a purchase price of not less than $50 million. Indebtedness under the Sunoco LP Credit Facility is secured by a security interest in, among other things, all of the Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all securityresult, these undivided interests securing the Sunoco LP Credit Facility will be released.
We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2014.are consolidated proportionately.
7.2.
REDEEMABLE NONCONTROLLING INTERESTS:
ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Change in Accounting Policy
During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows:
 Year Ended December 31, 2016 Year Ended December 31, 2015
 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted
Consolidated Statement of Operations and Comprehensive Income:           
Cost of products sold$15,039
 $41
 $15,080
 $26,682
 $32
 $26,714
Operating income1,802
 (41) 1,761
 2,259
 (32) 2,227
Income before income tax benefit438
 (41) 397
 1,398
 (32) 1,366
Net income624
 (41) 583
 1,521
 (32) 1,489
Net income attributable to partners297
 (9) 288
 1,398
 (9) 1,389
Net loss per common unit - basic(1.37) (0.01) (1.38) (0.06) (0.01) (0.07)
Net loss per common unit - diluted(1.37) (0.01) (1.38) (0.07) (0.01) (0.08)
Comprehensive income628
 (41) 587
 1,581
 (32) 1,549
Comprehensive income attributable to partners301
 (9) 292
 1,458
 (9) 1,449
            
Consolidated Statements of Cash Flows:           
Net income624
 (41) 583
 1,521
 (32) 1,489
Net change in operating assets and liabilities (change in inventories)(117) (129) (246) (1,367) 194
 (1,173)
            
Consolidated Balance Sheets (at period end):           
Inventories1,712
 (86) 1,626
 1,213
 (45) 1,168
Total partners' capital18,642
 (21) 18,621
 20,836
 (12) 20,824
* Amounts reflect certain reclassifications made to conform to the current year presentation.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Recent Accounting Pronouncements
ASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.
For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of our midstream segment agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.
ASU 2016-02
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-16
On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.
ASU 2017-12
In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
Revenue Recognition
Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the

pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.
In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and segment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.
In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

Regulatory Accounting – Regulatory Assets and Liabilities
Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:
 Years Ended December 31,
 2017 2016 2015
Accounts receivable$(950) $(919) $819
Accounts receivable from related companies67
 30
 (243)
Inventories37
 (497) (157)
Other current assets39
 83
 (178)
Other non-current assets, net(94) (78) 188
Accounts payable758
 972
 (1,215)
Accounts payable to related companies(3) 29
 (160)
Accrued and other current liabilities(47) 39
 (83)
Other non-current liabilities24
 33
 (219)
Price risk management assets and liabilities, net9
 62
 75
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations$(160) $(246) $(1,173)

Non-cash investing and financing activities and supplemental cash flow information are as follows:
 Years Ended December 31,
 2017 2016 2015
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$1,059
 $822
 $896
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP—
 194
 —
Net gains from subsidiary common unit transactions—
 37
 300
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with the PennTex Acquisition$—
 $307
 $—
Issuance of Common Units in connection with the Regency Merger—
 —
 9,250
Issuance of Class H Units in connection with the Bakken Pipeline Transaction—
 —
 1,946
Contribution of assets from noncontrolling interest988
 —
 34
Redemption of Common Units in connection with the Bakken Pipeline Transaction—
 —
 999
Redemption of Common Units in connection with the Sunoco LP Exchange—
 —
 52
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$1,329
 $1,411
 $1,467
Cash paid for (refund of) income taxes50
 (229) 71
Accounts Receivable
Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.
We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.
We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories
As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017.
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Inventories consisted of the following:
 December 31,
 2017 2016
Natural gas, NGLs, and refined products$733
 $758
Crude oil551
 651
Spare parts and other305
 217
Total inventories$1,589
 $1,626
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Other Current Assets
Other current assets consisted of the following:
 December 31,
 2017 2016
Deposits paid to vendors$64
 $74
Prepaid expenses and other146
 224
Total other current assets$210
 $298
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:
 December 31,
 2017 2016
Land and improvements$1,706
 $676
Buildings and improvements (1 to 45 years)1,960
 1,617
Pipelines and equipment (5 to 83 years)44,050
 36,356
Natural gas and NGL storage facilities (5 to 46 years)1,681
 1,452
Bulk storage, equipment and facilities (2 to 83 years)3,036
 3,701
Vehicles (1 to 25 years)124
 217
Right of way (20 to 83 years)3,424
 3,349
Natural resources434
 434
Other (1 to 40 years)534
 484
Construction work-in-process10,750
 9,934
 67,699
 58,220
Less – Accumulated depreciation and depletion(9,262) (7,303)
Property, plant and equipment, net$58,437
 $50,917
We recognized the following amounts for the periods presented:
 Years Ended December 31,
 2017 2016 2015
Depreciation and depletion expense$2,060
 $1,793
 $1,713
Capitalized interest283
 199
 163
Advances to and Investments in Unconsolidated Affiliates
We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
 December 31,
 2017 2016
Regulatory assets$85
 $86
Deferred charges210
 217
Restricted funds192
 190
Long-term affiliated receivable85
 90
Other186
 89
Total other non-current assets, net$758
 $672
(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.
Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.

Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:
 December 31, 2017 December 31, 2016
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:       
Customer relationships, contracts and agreements (3 to 46 years)$6,250
 $(1,003) $5,362
 $(737)
Patents (10 years)48
 (26) 48
 (21)
Trade Names (20 years)66
 (25) 66
 (22)
Other (5 to 20 years)1
 —
 2
 (2)
Total intangible assets$6,365
 $(1,054) $5,478
 $(782)
Aggregate amortization expense of intangible assets was as follows:
 Years Ended December 31,
 2017 2016 2015
Reported in depreciation, depletion and amortization$272
 $193
 $216
Estimated aggregate amortization expense for the next five years is as follows:
Years Ending December 31: 
2018$280
2019278
2020278
2021268
2022256
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
In 2015, we recorded $24 million of intangible asset impairments related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:
 Intrastate
Transportation
and Storage		 Interstate
Transportation and Storage		 Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services All Other Total
Balance, December 31, 2015$10
 $912
 $718
 $772
 $912
 $2,104
 $5,428
Reduction due to contribution of legacy Sunoco, Inc. retail business—
 —
 —
 —
 —
 (1,289) (1,289)
Acquired—
 —
 177
 —
 251
 —
 428
Impaired—
 (638) (32) —
 —
 —
 (670)
Balance, December 31, 201610
 274
 863
 772
 1,163
 815
 3,897
Acquired—
 —
 8
 —
 4
 —
 12
Impaired—
 (262) —
 (79) —
 (452) (793)
Other—
 —
 (1) —
 —
 —
 (1)
Balance, December 31, 2017$10
 $12
 $870
 $693
 $1,167
 $363
 $3,115
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve.
During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.
The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted

risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Long-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
 December 31,
 2017 2016
Interest payable$443
 $440
Customer advances and deposits59
 56
Accrued capital expenditures1,006
 749
Accrued wages and benefits208
 212
Taxes payable other than income taxes108
 63
Exchanges payable154
 208
Other165
 177
Total accrued and other current liabilities$2,143
 $1,905
Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests
The noncontrolling interest holders in one of Sunoco Logistics’our consolidated subsidiaries havehas the option to sell theirits interests to Sunoco Logistics.us.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheetsheet.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2014.2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $32.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
8.EQUITY:
Limited Partner interestsWe have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are representedaccounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by Common, Class E Units, Class G Unitsusing the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and Class H Units that entitleliabilities. We consider the holders thereofvaluation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the rights and privileges specifiedlevel of activity of these contracts on the exchange in which they trade. We consider the Partnership Agreement. Asvaluation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2014, there2017, no transfers were issuedmade between any levels within the fair value hierarchy.

The following tables summarize the fair value of our financial assets and outstanding 355.5 million Common Units representing an aggregate 99.3% Limited Partner interest in us. A totalliabilities measured and recorded at fair value on a recurring basis as of 8.9 million Class E UnitsDecember 31, 2017 and 90.7 million Class G Units are outstanding and are reported as treasury units, which units are entitled2016 based on inputs used to receive distributions in accordance withderive their terms. A total of 50.2 million Class H Units are also outstanding representing Limited Partner interests owned by ETE Holdings (see “Class H Units” below).fair values:
No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance.
IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs.
 Fair Value Total Fair Value Measurements at December 31, 2017
 Level 1 Level 2
Assets:     
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX$11
 $11
 $—
Swing Swaps IFERC13
 —
 13
Fixed Swaps/Futures70
 70
 —
Forward Physical Swaps8
 —
 8
Power:     
Forwards23
 —
 23
Natural Gas Liquids – Forwards/Swaps193
 193
 —
Crude – Futures2
 2
 —
Total commodity derivatives320
 276
 44
Other non-current assets21
 14
 7
Total assets$341
 $290
 $51
Liabilities:     
Interest rate derivatives$(219) $—
 $(219)
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX(24) (24) —
Swing Swaps IFERC(15) (1) (14)
Fixed Swaps/Futures(57) (57) —
Forward Physical Swaps(2) —
 (2)
Power – Forwards(22) —
 (22)
Natural Gas Liquids – Forwards/Swaps(192) (192) —
Refined Products – Futures(25) (25) —
Crude – Futures(1) (1) —
Total commodity derivatives(338) (300) (38)
Total liabilities$(557) $(300) $(257)

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Table of Contents
 Fair Value Total Fair Value Measurements at December 31, 2016
 Level 1 Level 2 Level 3
Assets:       
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX$14
 $14
 $—
 $—
Swing Swaps IFERC2
 —
 2
 —
Fixed Swaps/Futures96
 96
 —
 —
Forward Physical Swaps1
 —
 1
 —
Power:       
Forwards4
 —
 4
 —
Futures1
 1
 —
 —
Options – Calls1
 1
 —
 —
Natural Gas Liquids – Forwards/Swaps233
 233
 —
 —
Refined Products – Futures1
 1
 —
 —
Crude – Futures9
 9
 —
 —
Total commodity derivatives362
 355
 7
 —
Other non-current assets13
 8
 5
 —
Total assets$375
 $363
 $12
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in the Legacy ETP Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) —
 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids – Forwards/Swaps(273) (273) —
 —
Refined Products – Futures(17) (17) —
 —
Crude – Futures(13) (13) —
 —
Total commodity derivatives(472) (464) (8) —
Total liabilities$(666) $(464) $(201) $(1)

Common Units
The change in Common Units was as follows:
 Years Ended December 31,
 2014 2013 2012
Number of Common Units, beginning of period333.8
 301.5
 225.5
Common Units issued in connection with the Susser Merger (see Note 3)15.8
 —
 —
Common Units redeemed in connection with the Lake Charles LNG Transaction (see Note 3)(18.7) —
 —
Common Units issued in connection with public offerings—
 13.8
 15.5
Common Units issued in connection with certain acquisitions—
 49.5
 57.4
Common Units redeemed for Class H Units—
 (50.2) —
Common Units issued in connection with the Distribution Reinvestment Plan2.8
 2.3
 1.0
Common Units issued in connection with Equity Distribution Agreements21.4
 16.9
 1.6
Repurchases of Common Units in open-market transactions—
 (0.4) —
Issuance of Common Units under equity incentive plans0.4
 0.4
 0.5
Number of Common Units, end of period355.5
 333.8
 301.5
Our Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”
Public Offerings
The following table summarizes our public offerings ofETE Common Units during the periods presented, all of which have been registered under the Securities Act of 1933 (as amended):years ended December 31, 2017, 2016 and 2015 was as follows:
Date Number of Common Units Price per Unit Net Proceeds
July 2012 15.5
 $44.57
 $671
April 2013 13.8
 48.05
 657
 Years Ended December 31,
 2017 2016 2015
Number of Common Units, beginning of period1,046.9
 1,044.8
 1,077.5
Conversion of Class D Units to ETE Common Units—
 —
 0.9
Repurchase of common units under buyback program—
 —
 (33.6)
Issuance of common units32.2
 2.1
 —
Number of Common Units, end of period1,079.1
 1,046.9
 1,044.8
Proceeds fromETE Equity Distribution Agreement
In March 2017, the offerings listed above werePartnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the year ended December 31, 2017.
ETE Series A Convertible Preferred Units
 Years Ended December 31,
 2017 2016 2015
Number of Series A Convertible Preferred Units, beginning of period329.3
 —
 —
Issuance of Series A Convertible Preferred Units—
 329.3
 —
Number of Series A Convertible Preferred Units, end of period329.3
 329.3
 —
On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56.
The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $450 million carrying value as of December 31, 2017.
ETE issued 329,295,770 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s

Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates.
ETE January 2017 Private Placement and ETP Unit Purchase
In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to repay amountspurchase 23.7 million newly issued ETP common units for approximately $568 million.
Common Unit Split
On July 27, 2015, ETE completed a two-for-one split of the Partnership’s outstanding common units by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015.
Repurchase Program
In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 33.6 million ETE Common Units under this program in 2015. No units were repurchased under this program in 2017 or 2016, and there was $936 million available to use under the ETP Credit Facility and/orprogram as of December 31, 2017.
Class D Units
In 2013, the Partnership issued 3,080,000 Class D Units of ETE pursuant to fundan agreement with a former executive. The Class D Units were convertible to ETE Common Units, subject to certain vesting requirements which were not met prior to the former executive’s termination in 2016.
Sale of Common Units by Subsidiaries
The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital expenditures and capital contributionstransaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to joint ventures, and for general partnership purposes.the issuances of subsidiary common units during the periods presented.
Sale of Common Units by ETP
ETP’s Equity Distribution Program
From time to time, we haveETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement.
In January 2013 andconnection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2013, we2017, ETP entered into an equity distribution agreements pursuant to which we may sell from time to time Common Units havingagreement with an aggregate offering prices ofprice up to $200 million and $800 million, respectively. $1.00 billion.

During the year ended December 31, 2014, we2017, ETP issued approximately 2.722.6 million units for $144$503 million, net of commissions of $2 million. No amounts of our Common Units remain available to be issued under our January 2013 and May 2013 equity distribution agreements.
In May 2014 and November 2014, we entered into equity distribution agreements pursuant to which we may sell from time to time Common Units having aggregate offering prices of up to $1.0 billion and $1.50 billion, respectively. During the year

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ended December 31, 2014, we issued approximately 18.8 million units for $1.08 billion, net of commissions of $11$5 million. As of December 31, 2014, approximately $1.41 billion2017, $752 million of ourETP’s Common Units remained available to be issued under ourETP’s currently effective equity distribution agreements.agreement.
ETP’s Equity Incentive Plan Activity
As discussed in Note 9, we issueETP issues ETP Common Units to employees and directors upon vesting of awards granted under ourETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by the PartnershipETP to satisfy tax-withholding obligations.
ETP’s Distribution Reinvestment Program
OurETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ourETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan.
During the years ended December 31, 2014, 20132017, 2016 and 2012,2015, aggregate distributions of approximately $155$228 million, $109$216 million, and $43$360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of approximately 6.125.5 million Common Units.
As of December 31, 2014,2017, a total of 7.320.8 million Common Units remain available to be issued under the existing registration statement.
August 2017 Units Offering
In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.
ETP Class E Units
There are currently 8.9 million ETP Class E Units outstanding, all of which are currently owned by HHI. The ETP Class E Units generally do not have any voting rights. The ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the Class E Unitholders, up to $1.41$1.41 per unit per year, with any excess thereof available for distribution to Unitholders other thanyear. As the holders of Class E Units in proportion to their respective interests. The Class E Units are treated as treasury units for accounting purposes because they are owned by a wholly-owned subsidiary, of ETP Holdco, Heritage Holdings, Inc.the cash distributions on those units are eliminated in ETP’s consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire some or all of the ETP Class E Units at a future date. All
ETP Class G Units
There are currently 90.7 million ETP Class G Units outstanding, all of the 8.9 million Class E Units outstandingwhich are held by a subsidiary and are reported as treasury units.
wholly-owned subsidiaries of ETP. The ETP Class G Units
In conjunction with the Sunoco Merger, we amended our partnership agreement to create Class F Units. The number of Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million, which included 40 million Class F Units issued in exchange for cash contributed by Sunoco, Inc. to us immediately prior to or concurrent with the closing of the Sunoco Merger. The Class F Units generally diddo not have any voting rights. The ETP Class FG Units wereare entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by usETP and ourits subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per ETP Class FG Unit per year. In April 2013, all of the outstanding Class F Units were exchanged for Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocationsAllocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in the consolidated financial statements.
ETP Class H Units and Class I Units
Currently Outstanding
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which arewere generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 50.05%90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 50.05%90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters.

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Pending Transaction
In December 2014, ETP and ETE announced the final terms of a transaction, whereby ETE will transfer 30.8 million ETP Common Units, ETE’s 45% interest in the Bakken pipeline project, and $879 million in cash in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, in April 2017.

ETP will also issue 100 Class I Units as described below. In addition, ETE and ETP agreed to reduce the IDR subsidies that ETE previously agreed to provide to ETP, with such reductions occurring in 2015 and 2016.
In connection with the transaction,Bakken Pipeline Transaction discussed in Note 3, in March 2015, ETP will also issueissued 100 ETP Class I Units. The ETP Class I Units will beare generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the ETP Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the ETP Class I Units and (ii) after making cash distributions to ETP Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in ourETP’s Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter endingended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash” inCash.” Subsequent to the column titled “Pro Forma for Class HApril 2017 merger of ETP and Sunoco Logistics, 100 Class I Units.”Units remain outstanding.
SalesBakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of CommonDakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
Class K Units
On December 29, 2016, ETP issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in ETP, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by Subsidiaries
WithETP from ETP Holdco. If ETP is unable to pay the Class K Unit quarterly distribution with respect to our investments in Sunoco Logisticsany quarter, the accrued and Sunoco LP, we account for the difference between the carrying amountunpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of our investment in and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.
As a result of Sunoco Logistics’ issuances of common units during the year ended December 31, 2014, we recognized increases in partners’ capital2017, a total of $113 million.101.5 million Class K Units were held by wholly-owned subsidiaries of ETP.
As a result of Sunoco LP’s issuances of common units during the year ended December 31, 2014, we recognized increases in partners’ capital of $62 million.
Sales of Common Units by Sunoco Logistics
Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.
In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. DuringIn connection with theyear ended ended December 31, 2014, Sunoco Logistics received proceeds of $477 million, net of commissions of $5 million, fromMerger, the issuance of 10.3 million common units pursuant to theprevious Sunoco Logistics equity distribution agreement which were used for general partnership purposes.was terminated.
ETP Series A and Series Preferred Units
In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit.
Additionally, Sunoco Logistics completedDistributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an overnight public offeringannual floating rate of 7.7 millionthe three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15,

2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for net proceeds$20.00 per common unit in cash. ETP now owns all of $362 million in September 2014. The net proceeds from this offering were used to repay outstanding borrowings under the $1.50 billion Sunoco Logistics Credit Facilityeconomic interests of PennTex, and for general partnership purposes.PennTex common units are no longer publicly traded or listed on the NASDAQ.
Sales of Common Units by Sunoco LP
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.
In October 2014 and November 2014,2016, Sunoco LP entered into an equity distribution agreement pursuant to which Sunoco LP may sell from time to time common units having aggregate offering prices of up to $400 million. Through December 31, 2016, Sunoco LP received net proceeds of $71 million from the issuance of 2.8 million Sunoco LP common units pursuant to such equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. From January 1, 2017 through December 31, 2017, Sunoco LP issued an aggregateadditional 1.3 million units with total net proceeds of 9.1$33 million, net of commissions of $0.3 million. As of December 31, 2017, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement.
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP.
On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership.
In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha Petroleum, Ltd as consideration for the contribution by Aloha to an underwritten public offering. Aggregateindirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries.
In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $405 million$213 million. The net proceeds from the offering were used to repay amounts outstanding balances under the $1.25 billion Sunoco LP Credit Facilityrevolving credit facility.
Sunoco LP Series A Preferred Units
On March 30, 2017, the Partnership purchased 12.0 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate purchase price of $300 million. The distribution rate of Sunoco LP Series A Preferred Units is10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference.
In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and fora 1% call premium plus accrued and unpaid quarterly distributions.
Contributions to Subsidiaries
The Parent Company indirectly owns the entire general partnership purposes.partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain

its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest.
Parent Company Quarterly Distributions of Available Cash
TheOur distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our Available Cashavailable cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Sunoco LP related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG.
Our distributions declared and paid with respect to our Unitholderscommon units for the periods presented were as follows:
Quarter Ended        Record DatePayment DateRate
December 31, 2014February 6, 2015February 19, 20150.2250
March 31, 2015May 8, 2015May 19, 20150.2450
June 30, 2015August 6, 2015August 19, 20150.2650
September 30, 2015November 5, 2015November 19, 20150.2850
December 31, 2015February 4, 2016February 19, 20160.2850
March 31, 2016 (1)
May 6, 2016May 19, 20160.2850
June 30, 2016 (1)
August 8, 2016August 19, 20160.2850
September 30, 2016 (1)
November 7, 2016November 18, 20160.2850
December 31, 2016 (1)
February 7, 2017February 21, 20170.2850
March 31, 2017 (1)
May 10, 2017May 19, 20170.2850
June 30, 2017 (1)
August 7, 2017August 21, 20170.2850
September 30, 2017 (1)
November 7, 2017November 20, 20170.2950
December 31, 2017 (1)
February 8, 2018February 20, 20180.3050
(1)
Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See additional information below.
Our distributions declared and paid with respect to our General PartnerConvertible Unit during the years ended December 31, 2016 and 2017 were as follows:
Quarter Ended          Record Date Payment Date  Rate
March 31, 2016 May 6, 2016 May 19, 2016 $0.1100
June 30, 2016 August 8, 2016 August 19, 2016 0.1100
September 30, 2016 November 7, 2016 November 18, 2016 0.1100
December 31, 2016 February 7, 2017 February 21, 2017 0.1100
March 31, 2017 May 10, 2017 May 19, 2017 0.1100
June 30, 2017 August 7, 2017 August 21, 2017 0.1100
September 30, 2017 November 7, 2017 November 20, 2017 0.1100
December 31, 2017 February 8, 2018 February 20, 2018 0.1100
ETP’s Quarterly Distributions of Available Cash
Under ETP’s limited partnership agreement, within forty-five45 days followingafter the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any of our fiscal quarters,ETP distributes all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partnergeneral partner in its solediscretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to provide for the properestablish cash reserves that it determines are necessary or appropriate to properly conduct of our business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for futureETP’s business. ETP will make quarterly distributions to partners with respectthe extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to any one or morethe general partner.

If cash distributions exceed $0.0833 per unit in a quarter, the holders of the next four quarters. Available Cash is more fully definedincentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in our Partnership Agreement.

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Ourthat amount. These distributions are referred to as “incentive distributions.”
As the holder of Available Cash from operating surplus, excludingEnergy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to our General Partner and Limited Partner interests are based on their respective interests as of the distribution record date. Incentive distributions allocated to our General Partner arebe paid by ETP will be determined based on the amount byhistorical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s general partner interest, Class I units and a portion of the outstanding ETP common units.
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount IDRs 
Partners (1)
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%
(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Distributions on common Unitholders exceed certain specified target levels,units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as set forthfollows:
Quarter Ended ETP Sunoco Logistics
December 31, 2014 $0.6633
 $0.4000
March 31, 2015 0.6767
 0.4190
June 30, 2015 0.6900
 0.4380
September 30, 2015 0.7033
 0.4580
December 31, 2015 0.7033
 0.4790
March 31, 2016 0.7033
 0.4890
June 30, 2016 0.7033
 0.5000
September 30, 2016 0.7033
 0.5100
December 31, 2016 0.7033
 0.5200
Distributions on common units declared and paid by Post-Merger ETP were as follows:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 16, 2017 $0.5350
June 30, 2017 August 7, 2017 August 15, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
December 31, 2017 February 8, 2018 February 14, 2018 0.5650

In connection with previous transactions, we have agreed to relinquish its right to the following amounts of incentive distributions in our Partnership Agreement.future periods:
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Distributions declared duringand paid by ETP to the Series A and Series B preferred unitholders were as follows:
 Distribution per Preferred Unit
Quarter Ended Record Date Payment Date Series A Series B
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
 $16.378
Sunoco LP Quarterly Distributions of Available Cash
The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Effective July 1, 2015, ETE exchanged 21 million ETP common units, owned by ETE, the owner of ETP’s general partner interest, for 100% of the general partner interest and all of the IDRs of Sunoco LP. ETP had previously owned our IDRs since September 2014, prior to that date the IDRs were owned by Susser.
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount Common Unitholders Holder of IDRs
Minimum Quarterly Distribution $0.4375 100% —%
First Target Distribution $0.4375 to $0.503125 100% —%
Second Target Distribution $0.503125 to $0.546875 85% 15%
Third Target Distribution $0.546875 to $0.656250 75% 25%
Thereafter Above $0.656250 50% 50%

Distributions declared and paid by Sunoco LP for the periods presented were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2011 February 7, 2012 February 14, 2012 $0.8938
March 31, 2012 May 4, 2012 May 15, 2012 0.8938
June 30, 2012 August 6, 2012 August 14, 2012 0.8938
September 30, 2012 November 6, 2012 November 14, 2012 0.8938
December 31, 2012 February 7, 2013 February 14, 2013 0.8938
March 31, 2013 May 6, 2013 May 15, 2013 0.8938
June 30, 2013 August 5, 2013 August 14, 2013 0.8938
September 30, 2013 November 4, 2013 November 14, 2013 0.9050
December 31, 2013 February 7, 2014 February 14, 2014 0.9200
March 31, 2014 May 5, 2014 May 15, 2014 0.9350
June 30, 2014 August 4, 2014 August 14, 2014 0.9550
September 30, 2014 November 3, 2014 November 14, 2014 0.9750
December 31, 2014 February 6, 2015 February 13, 2015 0.9950
In connection with transactions between ETP and ETE, ETE has agreed to relinquish its right to certain incentive distributions in future periods. Following is a summary of the net reduction in total distributions that would potentially be made to ETE in future periods based on (i) the currently effective partnership agreement provisions, (ii) the assumed closing of the issuance of additional Class H Units and Class I Units, which is expected to occur in March 2015, and (iii) the assumed closing of the Regency Merger, which is expected to occur in the second quarter of 2015:
Years Ending December 31, Currently Effective 
Pro Forma for Class H and Class I Units(1)
 
Pro Forma for Regency Merger(2)
2015 $86
 $31
 $91
2016 107
 77
 142
2017 85
 85
 145
2018 80
 80
 140
2019 70
 70
 130
2020 35
 35
 50
2021 35
 35
 35
2022 35
 35
 35
2023 35
 35
 35
2024 18
 18
 18
(1)
Quarter Ended		Pro forma amounts reflect the IDR subsidies, as adjusted for the pending issuance of additional Class H Units and Class I Units discussed above, as well as distributions on the Class I Units. The issuance of additional Class H Units and Class I Units is expected to close in March 2015.
Record DatePayment DateRate
(2)
December 31, 2014		Pro forma amounts reflect the IDR subsidies, as adjusted for (i) the pending issuance of additional Class H Units and Class I Units (as described in Note (1) above) and (ii) the pending Regency Merger. Amounts reflected above assume that the Regency Merger is closed subsequent to the record date for the first quarter ofFebruary 17, 2015 distribution payment and prior to the record date for the second quarterFebruary 27, 2015 distribution payment.0.6000
March 31, 2015May 19, 2015May 29, 20150.6450
June 30, 2015August 18, 2015August 28, 20150.6934
September 30, 2015November 17, 2015November 27, 20150.7454
December 31, 2015February 5, 2016February 16, 20160.8013
March 31, 2016May 6, 2016May 16, 20160.8173
June 30, 2016August 5, 2016August 15, 20160.8255
September 30, 2016November 7, 2016November 15, 20160.8255
December 31, 2016February 13, 2017February 21, 20170.8255
March 31, 2017May 9, 2017May 16, 20170.8255
June 30, 2017August 7, 2017August 15, 20170.8255
September 30, 2017November 7, 2017November 14, 20170.8255
December 31, 2017February 06, 2018February 14, 20180.8255
The amounts reflected above include the relinquishment of $350 million in the aggregate of incentive distributions that would potentially be made to ETE over the first forty fiscal quarters commencing immediately after the consummation of the Susser

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Merger. Such relinquishments would cease upon the agreement of an exchange of the Sunoco LP general partner interest and the incentive distribution rights between ETE and ETP.
Sunoco Logistics Quarterly Distributions of Available Cash
Distributions declared during the periods presented were as follows:
Quarter Ended Record Date Payment Date Rate
December 31, 2012 February 8, 2013 February 14, 2013 $0.2725
March 31, 2013 May 9, 2013 May 15, 2013 0.2863
June 30, 2013 August 8, 2013 August 14, 2013 0.3000
September 30, 2013 November 8, 2013 November 14, 2013 0.3150
December 31, 2013
February 10, 2014 February 14, 2014 0.3312
March 31, 2014 May 9, 2014 May 15, 2014 0.3475
June 30, 2014 August 8, 2014 August 14, 2014 0.3650
September 30, 2014 November 7, 2014 November 14, 2014 0.3825
December 31, 2014 February 9, 2015 February 13, 2015 0.4000
Sunoco Logistics Unit Split
On May 5, 2014, Sunoco Logistics’ board of directors declared a two-for-one split of Sunoco Logistics common units. The unit split resulted in the issuance of one additional Sunoco Logistics common unit for every one unit owned as of the close of business on June 5, 2014. The unit split was effective June 12, 2014. All Sunoco Logistics unit and per unit information included in this report is presented on a post-split basis.
Sunoco LP Quarterly Distributions of Available Cash
Distributions declared by Sunoco LP subsequent to our acquisition on August 29, 2014 were as follows:
Quarter Ended Record Date Payment Date Rate
September 30, 2014 November 18, 2014 November 28, 2014 $0.5457
December 31, 2014 February 17, 2015 February 27, 2015 0.6000
Accumulated Other Comprehensive Income (Loss)
The following table presents the components of AOCI, net of tax:
December 31,December 31,
2014 20132017 2016
Available-for-sale securities$3
 $2
$8
 $2
Foreign currency translation adjustment(3) (1)(5) (5)
Net loss on commodity related hedges(1) (4)
Actuarial gain (loss) related to pensions and other postretirement benefits(57) 56
(5) 7
Investments in unconsolidated affiliates, net2
 8
5
 4
Total AOCI, net of tax$(56) $61
Subtotal3
 8
Amounts attributable to noncontrolling interest(3) (8)
Total AOCI included in partners’ capital, net of tax$—
 $—

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The tablestable below setsets forth the tax amounts included in the respective components of other comprehensive income (loss):
 December 31,
 2017 2016
Available-for-sale securities$(2) $(2)
Foreign currency translation adjustment3
 3
Actuarial loss relating to pension and other postretirement benefits3
 —
Total$4
 $1
9.UNIT-BASED COMPENSATION PLANS:
We, ETP and Sunoco LP have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards.
ETE Long-Term Incentive Plan
The Board of Directors or the Compensation Committee of the board of directors of our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom

units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 12.0 million units. As of December 31, 2017, 10.8 million units remain available to be awarded under the plan.
During the year ended December 31, 2017, 1.2 million ETE unit awards were granted to ETE employees and certain employees of ETP and 15,648 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest 60% in three years and 40% in five years and do not entitle the holders to receive distributions during the vesting period.
During the year ended December 31, 2017 and 2016, a total of 2,018 and 28,648 ETE Common Units vested, with a total fair value of $39 thousand and $205 thousand, respectively, as of the vesting date. As of December 31, 2017, a total of 1,251,002 restricted units remain outstanding, for which we expect to recognize a total of $21 million in compensation over a weighted average period of 3.5 years.
Subsidiary Unit-Based Compensation Plans
Each of ETP and Sunoco LP has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards” to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a five-year period, and vesting The Subsidiary Unit Awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding.
The following table summarizes the activity of the Subsidiary Unit Awards:
 ETP Sunoco LP
 
Number of
Units
 
Weighted  Average
Grant-Date Fair Value
Per Unit
 
Number of
Units
 
Weighted  Average
Grant-Date Fair Value
Per Unit
Unvested awards as of December 31, 20169.4
 $27.68
 2.0
 $34.43
Legacy Sunoco Logistics unvested awards as of December 31, 20163.2
 28.57
 —
 —
Awards granted4.9
 17.69
 0.2
 28.31
Awards vested(2.3) 34.22
 (0.3) 45.48
Awards forfeited(1.1) 25.03
 (0.2) 34.71
Unvested awards as of December 31, 201714.1
 23.18
 1.7
 31.89
Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31:       
2017  $17.69
   $28.31
2016  23.82
   26.95
2015  23.47
   40.63
The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2017, 2016, and 2015 was $40 million, $40 million, and $57 million, respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $216 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.8 years.

10.INCOME TAXES:
As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows:
 Years Ended December 31,
 2017 2016 2015
Current expense (benefit):     
Federal$54
 $(47) $(308)
State(16) (34) (54)
Total38
 (81) (362)
Deferred expense (benefit):     
Federal(2,055) (189) 268
State184
 12
 (29)
Total(1,871) (177) 239
Total income tax expense (benefit) from continuing operations$(1,833) $(258) $(123)
Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense (benefit) at the United States statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2017, 2016 and 2015 is as follows:
 2017 2016 2015
Income tax expense (benefit) at United States statutory rate of 35 percent$248
 $71
 $316
Increase (reduction) in income taxes resulting from:     
Partnership earnings not subject to tax(477) (576) (355)
Goodwill impairment207
 278
 —
State tax, net of federal tax benefit124
 (10) (29)
Dividend received deduction(14) (15) (22)
Federal rate change(1,812) —
 —
Audit settlement—
 —
 (7)
Change in tax status of subsidiary(124) —
 —
Other15
 (6) (26)
Income tax expense (benefit) from continuing operations$(1,833) $(258) $(123)

Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
 December 31,
 2017 2016
Deferred income tax assets:   
Net operating losses and alternative minimum tax credit$683
 $472
Pension and other postretirement benefits21
 30
Long-term debt14
 32
Other191
 182
Total deferred income tax assets909
 716
Valuation allowance(189) (118)
Net deferred income tax assets720
 598
    
Deferred income tax liabilities:   
Property, plant and equipment(1,036) (1,633)
Investments in unconsolidated affiliates(2,726) (3,789)
Trademarks(173) (273)
Other(100) (15)
Total deferred income tax liabilities(4,035) (5,710)
Net deferred income taxes$(3,315) $(5,112)
The table below provides a rollforward of the net deferred income tax liability as follows:
 December 31,
 2017 2016
Net deferred income tax liability, beginning of year$(5,112) $(4,590)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)—
 (460)
Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3)—
 (243)
Tax provision, including provision from discontinued operations1,825
 201
Other(28) (20)
Net deferred income tax liability$(3,315) $(5,112)
ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $403 million, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $62 million of federal alternative minimum tax credits at December 31, 2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have net operating loss carryforward benefits of $274 million, $217 million net of federal tax, which expire between January 1, 2018 and 2037. A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.

The following table sets forth the changes in unrecognized tax benefits:
 Years Ended December 31,
 2017 2016 2015
Balance at beginning of year$615
 $610
 $440
Additions attributable to tax positions taken in the current year—
 8
 178
Additions attributable to tax positions taken in prior years28
 18
 —
Reduction attributable to tax positions taken in prior years(25) (20) —
Lapse of statute(9) (1) (8)
Balance at end of year$609
 $615
 $610
As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $9 million, net of tax.
Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in its litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2017.
In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety.  In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact.  Nextel has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court.  Sunoco, Inc. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter.  However, based upon the Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 million after federal income tax benefits) against the receivable.
In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.
Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments.
ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.
Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefit of $1.81 billion in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

11.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Contingent Residual Support Agreement – AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.
Guarantee of Sunoco LP Notes
In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
$1.00 billion aggregate principal amount of 4.875%, senior notes due 2023;
$800 million aggregate principal amount of 5.50% senior notes due 2026; and
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.
FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.
Commitments
In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.
ETP’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
  Years Ended December 31,
  2017 2016 2015
Rental expense(1)
 $196
 $187
 $281
Less: Sublease rental income (25) (26) (26)
Rental expense, net $171
 $161
 $255
(1)
Includes contingent rentals totaling $16 million, $18 million and $20 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Future minimum lease commitments for such leases are:
Years Ending December 31: 
2018$113
2019100
202096
202183
202271
Thereafter606
Future minimum lease commitments1,069
Less: Sublease rental income(152)
Net future minimum lease commitments$917
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
Dakota Access Pipeline
On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.
After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.
The SRST appealed the denial of the preliminary injunction to the United States Court of Appeals for the D.C. Circuit and filed an emergency motion in the United States District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.
In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the Tribe. The District Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.

The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes.
On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018.
On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access is required to file the revised plan with the Court by April 1, 2018. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first report was filed with the court on December 29, 2017.
In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. Briefing on YST’s motion is ongoing.
While we believe that the pending lawsuits are unlikely to halt or suspend the operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.
MTBE Litigation
Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2017, Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is

pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland.
Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Regency Merger Litigation
Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”).
The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC.
The Regency Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP filed a petition for review with the Texas Supreme Court. Enterprise’s response is due February 26, 2018.
Sunoco Logistics Merger Litigation
Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well

as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017.
The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger.
Litigation Filed By or Against Williams
On April 6, 2016, Williams filed a complaint, The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware Williams Litigation”). Williams sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware Williams Litigation. The counterclaim asserts in general that Williams materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow Williams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Issuance against Mr. Warren in the District Court of Dallas County, Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause.
On May 13, 2016, Williams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al., C.A. No. 12337-VCG (the “Second Delaware Williams Litigation”). In general, Williams alleged that Defendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) breaching a representation and warranty in the Merger Agreement concerning Section 721 of the Internal Revenue Code, and (c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. Williams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions.
ETE filed an answer and counterclaim in the Second Delaware Williams Litigation. In addition to the counterclaims previously asserted, ETE asserted that Williams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the Williams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, (c) failing to facilitate the financing of the merger, (d) failing to use its reasonable best efforts to consummate the merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016.
After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied Williams’ requests for injunctive relief. The Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016.
Williams filed an amended complaint on September 16, 2016 and sought a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Defendants breached an additional representation and warranty in the Merger Agreement.
Defendants filed amended counterclaims and affirmative defenses on September 23, 2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On

September 29, 2016, Williams filed a motion to dismiss Defendants’ amended counterclaims and to strike certain of Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016.
On March 23, 2017, the Delaware Supreme Court affirmed the Court of Chancery’s Opinion and Order on the June 2016 trial and denied Williams’ motion for reargument on April 5, 2017. As a result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.
Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are without merit and intend to defend vigorously against them.
Unitholder Litigation Relating to the Issuance
In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016.
The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance.
On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, and in addition to the injunctive relief described above, seek class-wide damages allegedly resulting from the Issuance.
The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is currently set for February 19-21, 2018.
The Issuance Defendants cannot predict the outcome of the Issuance Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation. The Issuance Defendants believe the Issuance Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Issuance.
Litigation filed by BP Products
On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.
SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.
On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.

On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.
Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2017 and 2016, accruals of approximately $33 million and $77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
No amounts have been recorded in our December 31, 2017 or 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million

for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 43 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
 December 31,
 2017 2016
Current$35
 $26
Non-current337
 318
Total environmental liabilities$372
 $344

In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the years ended December 31, 2017 and 2016, the Partnership recorded $32 million and $43 million, respectively, of expenditures related to environmental cleanup programs.
On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (TRC) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period.  On January 2, 2013, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations.  To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery.  Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to its results of operations, cash flows or financial position.
Our pipeline operations are subject to regulation by the United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
In January 2012, ETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which ETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. ETP has also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, ETP received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of ETP’s Permian Express 2 pipeline system in Texas.  The proposed penalties are in excess of $100,000. The case went to hearing in November 2016 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.

In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
12.DERIVATIVE ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream operations whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage operations’ and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other operations which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table details our outstanding commodity-related derivatives:
 December 31, 2017 December 31, 2016
 
Notional
Volume
 Maturity 
Notional
Volume
 Maturity
Mark-to-Market Derivatives       
(Trading)       
Natural Gas (BBtu):       
Fixed Swaps/Futures1,078
 2018 (683) 2017
Basis Swaps IFERC/NYMEX (1)
48,510
 2018-2020 2,243
 2017
Options – Puts13,000
 2018 —
 —
Power (Megawatt):       
Forwards435,960
 2018-2019 391,880
 2017 - 2018
Futures(25,760) 2018 109,564
 2017 - 2018
Options — Puts(153,600) 2018 (50,400) 2017
Options — Calls137,600
 2018 186,400
 2017
Crude (MBbls) – Futures—
 — (617) 2017
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX4,650
 2018-2020 10,750
 2017 - 2018
Swing Swaps IFERC87,253
 2018-2019 (5,663) 2017
Fixed Swaps/Futures(4,390) 2018-2019 (52,653) 2017 - 2019
Forward Physical Contracts(145,105) 2018-2020 (22,492) 2017
Natural Gas Liquid (MBbls) – Forwards/Swaps6,744
 2018-2019 (5,787) 2017
Refined Products (MBbls) – Futures(3,901) 2018-2019 (3,144) 2017
Corn (Bushels) – Futures1,870,000
 2018 1,580,000
 2017
Fair Value Hedging Derivatives       
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX(39,770) 2018 (36,370) 2017
Fixed Swaps/Futures(39,770) 2018 (36,370) 2017
Hedged Item — Inventory39,770
 2018 36,370
 2017
(1)
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which are designated as hedges for accounting purposes:
      Notional Amount Outstanding
Entity Term 
Type(1)
 December 31, 2017 December 31, 2016
ETP 
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
ETP 
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
ETP 
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
ETP 
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
ETP December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
ETP March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
(1)
Floating rates are based on 3-month LIBOR.
(2)
Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date.
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies, and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
 Fair Value of Derivative Instruments
 Asset Derivatives Liability Derivatives
 December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives designated as hedging instruments:       
Commodity derivatives (margin deposits)$14
 $—
 $(2) $(4)
 14
 —
 (2) (4)
Derivatives not designated as hedging instruments:       
Commodity derivatives (margin deposits)262
 338
 (281) (416)
Commodity derivatives45
 25
 (58) (58)
Interest rate derivatives—
 —
 (219) (193)
Embedded derivatives in ETP Convertible Preferred Units—
 —
 —
 (1)
 307
 363
 (558) (668)
Total derivatives$321
 $363
 $(560) $(672)
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
    Asset Derivatives Liability Derivatives
  Balance Sheet Location December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives without offsetting agreements Derivative assets (liabilities) $—
 $—
 $(219) $(194)
Derivatives in offsetting agreements:        
OTC contracts Derivative assets (liabilities) 45
 25
 (58) (58)
Broker cleared derivative contracts Other current assets (liabilities) 276
 338
 (283) (420)
  321
 363
 (560) (672)
Offsetting agreements:        
Counterparty netting Derivative assets (liabilities) (21) (4) 21
 4
Counterparty netting Other current assets (liabilities) (263) (338) 263
 338
Total net derivatives $37
 $21
 $(276) $(330)
We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to our derivative financial instruments:
 
Location of Gain/(Loss)
Recognized in
Income on Derivatives
 
Amount of Gain/(Loss) Recognized in Income
Representing Hedge Ineffectiveness and
Amount Excluded from the Assessment of
Effectiveness
 Years Ended December 31,
 2017 2016 2015
Derivatives in fair value hedging relationships (including hedged item):       
Commodity derivativesCost of products sold $26
 $14
 $21
Total  $26
 $14
 $21
 Location of Gain/(Loss) Recognized in Income on Derivatives 
Amount of Gain/(Loss) Recognized
in Income on Derivatives
  Years Ended December 31,
  2017 2016 2015
Derivatives not designated as hedging instruments:       
Commodity derivatives – TradingCost of products sold $31
 $(35) $(11)
Commodity derivatives – Non-tradingCost of products sold 5
 (177) 15
Interest rate derivativesLosses on interest rate derivatives (37) (12) (18)
Embedded derivativesOther, net 1
 4
 12
Total  $—
 $(220) $(2)

13.RETIREMENT BENEFITS:
Savings and Profit Sharing Plans
We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETP, Sunoco LP and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $38 million, $44 million and $40 million to the 401(k) savings plan for the years ended December 31, 2017, 2016, and 2015, respectively.
Pension and Other Postretirement Benefit Plans
Panhandle
Postretirement benefits expense for the years ended December 31, 2017, 2016, and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.
Sunoco, Inc.
Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.
Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.

The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
 December 31, 2017 December 31, 2016
 Pension Benefits   Pension Benefits  
 Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Change in benefit obligation:           
Benefit obligation at beginning of period$18
 $51
 $166
 $20
 $57
 $181
Interest cost1
 1
 4
 1
 2
 4
Amendments—
 —
 7
 —
 —
 —
Benefits paid, net(2) (6) (20) (1) (7) (21)
Actuarial (gain) loss and other2
 1
 (1) (2) (1) 2
Settlements(18) —
 —
 —
 —
 —
Benefit obligation at end of period$1
 $47
 $156
 $18
 $51
 $166
            
Change in plan assets:           
Fair value of plan assets at beginning of period$12
 $—
 $256
 $15
 $—
 $261
Return on plan assets and other3
 —
 11
 (2) —
 6
Employer contributions6
 —
 10
 —
 —
 10
Benefits paid, net(2) —
 (20) (1) —
 (21)
Settlements(18) —
 —
 —
 —
 —
Fair value of plan assets at end of period$1
 $—
 $257
 $12
 $—
 $256
            
Amount underfunded (overfunded) at end of period$—
 $47
 $(101) $6
 $51
 $(90)
            
Amounts recognized in the consolidated balance sheets consist of:           
Non-current assets$—
 $—
 $127
 $—
 $—
 $114
Current liabilities—
 (8) (2) —
 (7) (2)
Non-current liabilities—
 (39) (24) (6) (44) (23)
 $—
 $(47) $101
 $(6) $(51) $89
            
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:           
Net actuarial gain$—
 $5
 $(18) $—
 $—
 $(13)
Prior service cost—
 —
 21
 —
 —
 15
 $—
 $5
 $3
 $—
 $—
 $2

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
 December 31, 2017 December 31, 2016
 Pension Benefits   Pension Benefits  
 Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Projected benefit obligation$1
 $47
 N/A
 $18
 $51
 N/A
Accumulated benefit obligation1
 47
 $156
 18
 51
 $166
Fair value of plan assets1
 —
 257
 12
 —
 256
Components of Net Periodic Benefit Cost
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Net Periodic Benefit Cost:       
Interest cost$2
 $4
 $3
 $4
Expected return on plan assets—
 (9) (1) (8)
Prior service cost amortization—
 2
 —
 1
Net periodic benefit cost$2
 $(3) $2
 $(3)
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.27% 2.34% 3.65% 2.34%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.52% 3.10% 3.60% 3.06%
Expected return on assets:       
Tax exempt accounts3.50% 7.00% 3.50% 7.00%
Taxable accountsN/A
 4.50% N/A
 4.50%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest

rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:
 December 31,
 2017 2016
Health care cost trend rate7.20% 6.73%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)4.99% 4.96%
Year that the rate reaches the ultimate trend rate2023
 2021
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%. 
The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.
The fair value of the pension plan assets by asset category at the dates indicated is as follows:
    Fair Value Measurements at December 31, 2017
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Mutual funds (1)
 $1
 $1
 $—
 $—
Total $1
 $1
 $—
 $—
(1)
Comprised of 100% equities as of December 31, 2017.
    Fair Value Measurements at December 31, 2016
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Mutual funds (1)
 $12
 $12
 $—
 $—
Total $12
 $12
 $—
 $—
(1)
Comprised of 100% equities as of December 31, 2016.

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
    Fair Value Measurements at December 31, 2017
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $33
 $33
 $—
 $—
Mutual funds (1)
 154
 154
 —
 —
Fixed income securities 70
 —
 70
 —
Total $257
 $187
 $70
 $—
(1)
Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% cash as of December 31, 2017.
    Fair Value Measurements at December 31, 2016
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $23
 $23
 $—
 $—
Mutual funds (1)
 142
 142
 —
 —
Fixed income securities 91
 —
 91
 —
Total $256
 $165
 $91
 $—
(1)
Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.
The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  
Contributions
We expect to contribute $8 million to pension plans and $10 million to other postretirement plans in 2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:
Years 
Pension Benefits - Unfunded Plans (1)
 Other Postretirement Benefits (Gross, Before Medicare Part D)
2018 $8
 $24
2019 6
 23
2020 6
 21
2021 5
 19
2022 4
 17
2023 – 2027 15
 37
(1)     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

14.RELATED PARTY TRANSACTIONS:
In June 2017, ETP acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8.
ETE previously paid ETP to provide services on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016.
In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million and $290 million during the years ended December 31, 2017, 2016 and 2015, respectively.
15.REPORTABLE SEGMENTS:
Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.
We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.
Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

Eliminations in the tables below include the following:
MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above.
 Years Ended December 31,
 2017 2016 2015
Revenues:     
Investment in ETP:     
Revenues from external customers$28,613
 $21,618
 $34,156
Intersegment revenues441
 209
 136
 29,054
 21,827
 34,292
Investment in Sunoco LP:     
Revenues from external customers11,713
 9,977
 12,419
Intersegment revenues10
 9
 11
 11,723
 9,986
 12,430
Investment in Lake Charles LNG:     
Revenues from external customers197
 197
 216
 

 

 

Adjustments and Eliminations:(451) (218) (10,842)
Total revenues$40,523
 $31,792
 $36,096
      
Costs of products sold:     
Investment in ETP$20,801
 $15,080
 $26,714
Investment in Sunoco LP10,615
 8,830
 11,450
Adjustments and Eliminations(450) (217) (9,496)
Total costs of products sold$30,966
 $23,693
 $28,668
      
Depreciation, depletion and amortization:     
Investment in ETP$2,332
 $1,986
 $1,929
Investment in Sunoco LP169
 176
 150
Investment in Lake Charles LNG39
 39
 39
Corporate and Other14
 15
 17
Adjustments and Eliminations—
 —
 (184)
Total depreciation, depletion and amortization$2,554
 $2,216
 $1,951
 Years Ended December 31,
 2017 2016 2015
Equity in earnings of unconsolidated affiliates:     
Investment in ETP$156
 $59
 $469
Adjustments and Eliminations(12) 211
 (193)
Total equity in earnings of unconsolidated affiliates$144
 $270
 $276

 Years Ended December 31,
 2017 2016 2015
Segment Adjusted EBITDA:     
Investment in ETP$6,712
 $5,733
 $5,517
Investment in Sunoco LP732
 665
 719
Investment in Lake Charles LNG175
 179
 196
Corporate and Other(31) (170) (104)
Adjustments and Eliminations(268) (272) (590)
Total Segment Adjusted EBITDA7,320
 6,135
 5,738
Depreciation, depletion and amortization(2,554) (2,216) (1,951)
Interest expense, net of interest capitalized(1,922) (1,804) (1,622)
Gains on acquisitions—
 83
 —
Impairment of investments in unconsolidated affiliates(313) (308) —
Impairment losses(1,039) (1,040) (339)
Losses on interest rate derivatives(37) (12) (18)
Non-cash unit-based compensation expense(99) (70) (91)
Unrealized gains (losses) on commodity risk management activities59
 (136) (65)
Losses on extinguishments of debt(89) —
 (43)
Inventory valuation adjustments24
 97
 (67)
Adjusted EBITDA related to discontinued operations(223) (199) (228)
Adjusted EBITDA related to unconsolidated affiliates(716) (675) (713)
Equity in earnings of unconsolidated affiliates144
 270
 276
Other, net155
 79
 23
Income from continuing operations before income tax benefit$710
 $204
 $900
Income tax benefit from continuing operations(1,833) (258) (123)
Income from continuing operations2,543
 462
 1,023
Income (loss) from discontinued operations, net of tax(177) (462) 38
Net income$2,366
 $—
 $1,061
 December 31,
 2017 2016 2015
Total assets:     
Investment in ETP$77,965
 $70,105
 $65,128
Investment in Sunoco LP8,344
 8,701
 8,842
Investment in Lake Charles LNG1,646
 1,508
 1,369
Corporate and Other598
 711
 638
Adjustments and Eliminations(2,307) (2,100) (4,833)
Total$86,246
 $78,925
 $71,144

 Years Ended December 31,
 2017 2016 2015
Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):     
Investment in ETP$5,901
 $5,810
 $8,167
Investment in Sunoco LP103
 119
 178
Investment in Lake Charles LNG2
 —
 1
Adjustments and Eliminations—
 —
 (123)
Total$6,006
 $5,929
 $8,223
 December 31,
 2017 2016 2015
Advances to and investments in affiliates:     
Investment in ETP$3,816
 $4,280
 $5,003
Adjustments and Eliminations(1,111) (1,240) (1,541)
Total$2,705
 $3,040
 $3,462
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP.
Investment in ETP
 Years Ended December 31,
 2017 2016 2015
Intrastate Transportation and Storage$2,891
 $2,155
 $1,912
Interstate Transportation and Storage915
 946
 1,008
Midstream2,510
 2,342
 2,607
NGL and refined products transportation and services8,326
 5,973
 4,569
Crude oil transportation and services11,672
 7,539
 8,980
All Other2,740
 2,872
 15,216
Total revenues29,054
 21,827
 34,292
Less: Intersegment revenues441
 209
 136
Revenues from external customers$28,613
 $21,618
 $34,156
Investment in Sunoco LP
 Years Ended December 31,
 2017 2016 2015
Retail operations$2,263
 $1,991
 $2,226
Wholesale operations9,460
 7,995
 10,204
Total revenues11,723
 9,986
 12,430
Less: Intersegment revenues10
 9
 11
Revenues from external customers$11,713
 $9,977
 $12,419
Investment in Lake Charles LNG
Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 2015, respectively, were related to LNG terminalling.

16.QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.
 Quarters Ended  
 March 31* June 30* September 30* December 31 Total Year
2017:         
Revenues$9,660
 $9,427
 $9,984
 $11,452
 $40,523
Operating income (loss)758
 746
 924
 285
 2,713
Net income (loss)319
 121
 758
 1,168
 2,366
Limited Partners’ interest in net income232
 204
 240
 239
 915
Basic net income per limited partner unit$0.22
 $0.18
 $0.22
 $0.22
 $0.85
Diluted net income per limited partner unit$0.21
 $0.18
 $0.22
 $0.22
 $0.83
 Quarters Ended  
 March 31* June 30* September 30* December 31* Total Year*
2016:         
Revenues$6,447
 $7,866
 $8,156
 $9,323
 $31,792
Operating income680
 814
 624
 (275) 1,843
Net income (loss)320
 417
 (3) (734) —
Limited Partners’ interest in net income311
 239
 207
 226
 983
Basic net income per limited partner unit$0.30
 $0.23
 $0.20
 $0.22
 $0.94
Diluted net income per limited partner unit$0.30
 $0.23
 $0.19
 $0.21
 $0.92
* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.
The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to ETP’s interstate transportation and storage operations, NGL and refined products operations and other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its interstate transportation and storage operations.

17.SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:
Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:
BALANCE SHEETS
 December 31,
 2017 2016
ASSETS   
CURRENT ASSETS:   
Cash and cash equivalents$1
 $2
Accounts receivable from related companies65
 55
Other current assets1
 —
Total current assets67
 57
PROPERTY, PLANT AND EQUIPMENT, net27
 36
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES6,082
 5,088
INTANGIBLE ASSETS, net—
 1
GOODWILL9
 9
OTHER NON-CURRENT ASSETS, net8
 10
Total assets$6,193
 $5,201
LIABILITIES AND PARTNERS’ CAPITAL   
CURRENT LIABILITIES:   
Accounts payable$—
 $1
Accounts payable to related companies—
 22
Interest payable66
 66
Accrued and other current liabilities4
 3
Total current liabilities70
 92
LONG-TERM DEBT, less current maturities6,700
 6,358
NOTE PAYABLE TO AFFILIATE617
 443
OTHER NON-CURRENT LIABILITIES2
 2
    
COMMITMENTS AND CONTINGENCIES
 
    
PARTNERS’ DEFICIT:   
General Partner(3) (3)
Limited Partners:   
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)(1,643) (1,871)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)450
 180
Total partners’ deficit(1,196) (1,694)
Total liabilities and partners’ deficit$6,193
 $5,201


STATEMENTS OF OPERATIONS
 Years Ended December 31,
 2017 2016 2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES$(31) $(185) $(112)
OTHER INCOME (EXPENSE):     
Interest expense, net of interest capitalized(347) (327) (294)
Equity in earnings of unconsolidated affiliates1,381
 1,511
 1,601
Loss on extinguishment of debt(47) —
 —
Other, net(2) (4) (5)
INCOME BEFORE INCOME TAXES954
 995
 1,190
Income tax expense—
 —
 1
NET INCOME954
 995
 1,189
General Partner’s interest in net income2
 3
 3
Convertible Unitholders’ interest in income37
 9
 —
Class D Unitholder’s interest in net income—
 —
 3
Limited Partners’ interest in net income$915
 $983
 $1,183


STATEMENTS OF CASH FLOWS
 Years Ended December 31,
 2017 2016 2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES$831
 $918
 $1,103
CASH FLOWS FROM INVESTING ACTIVITIES:     
Cash paid for Bakken Pipeline Transaction—
 —
 (817)
Contributions to unconsolidated affiliates(861) (70) —
Capital expenditures(1) (16) (19)
Contributions in aid of construction costs7
 —
 —
Net cash used in investing activities(855) (86) (836)
CASH FLOWS FROM FINANCING ACTIVITIES:     
Proceeds from borrowings2,219
 225
 3,672
Principal payments on debt(1,881) (210) (1,985)
Distributions to partners(1,010) (1,022) (1,090)
Proceeds from affiliate174
 176
 210
Common Units issued for cash568
 —
 —
Units repurchased under buyback program—
 —
 (1,064)
Debt issuance costs(47) —
 (11)
Net cash provided by (used in) financing activities23
 (831) (268)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(1) 1
 (1)
CASH AND CASH EQUIVALENTS, beginning of period2
 1
 2
CASH AND CASH EQUIVALENTS, end of period$1
 $2
 $1


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS
OF CERTAIN SUBSIDIARIES INCLUDED PURSUANT
TO RULE 3-16 OF REGULATION S-X
Page
1. Energy Transfer Partners, L.P. Financial StatementsS - 2


1.ENERGY TRANSFER PARTNERS, L.P. FINANCIAL STATEMENTS


INDEX TO FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting FirmS - 3
Consolidated Balance Sheets – December 31, 2017 and 2016S - 4
Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 and 2015S - 6
Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 and 2015S - 7
Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 and 2015S - 8
Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 and 2015S - 10
Notes to Consolidated Financial StatementsS - 12

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors of Energy Transfer Partners, L.L.C. and
Unitholders of Energy Transfer Partners, L.P.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 2018 (not separately included herein) expressed an unqualified opinion thereon.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2004.

Dallas, Texas
February 23, 2018


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
ASSETS   
Current assets:   
Cash and cash equivalents$306
 $360
Accounts receivable, net3,946
 3,002
Accounts receivable from related companies318
 209
Inventories1,589
 1,626
Income taxes receivable135
 128
Derivative assets24
 20
Other current assets210
 298
Total current assets6,528
 5,643
    
Property, plant and equipment67,699
 58,220
Accumulated depreciation and depletion(9,262) (7,303)
 58,437
 50,917
    
Advances to and investments in unconsolidated affiliates3,816
 4,280
Other non-current assets, net758
 672
Intangible assets, net5,311
 4,696
Goodwill3,115
 3,897
Total assets$77,965
 $70,105
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable$4,126
 $2,900
Accounts payable to related companies209
 43
Derivative liabilities109
 166
Accrued and other current liabilities2,143
 1,905
Current maturities of long-term debt407
 1,189
Total current liabilities6,994
 6,203
    
Long-term debt, less current maturities32,687
 31,741
Long-term notes payable – related company—
 250
Non-current derivative liabilities145
 76
Deferred income taxes2,883
 4,394
Other non-current liabilities1,084
 952
    
Commitments and contingencies
 

Legacy ETP Preferred Units—
 33
Redeemable noncontrolling interests21
 15
    
Equity:   
Series A Preferred Units (950,000 units authorized, issued and outstanding as of December 31, 2017)944
 —
Series B Preferred Units (550,000 units authorized, issued and outstanding as of December 31, 2017)547
 —
Limited Partners:   
Common Unitholders (1,164,112,575 and 794,803,854 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)26,531
 14,925
Class E Unitholder (8,853,832 units authorized, issued and outstanding – held by subsidiary)—
 —
Class G Unitholder (90,706,000 units authorized, issued and outstanding – held by subsidiary)—
 —
Class H Unitholder (81,001,069 units authorized, issued and outstanding as of December 31, 2016)—
 3,480
Class I Unitholder (100 units authorized, issued and outstanding)—
 2
Class K Unitholders (101,525,429 units authorized, issued and outstanding – held by subsidiaries)—
 —
General Partner244
 206
Accumulated other comprehensive income3
 8
Total partners’ capital28,269
 18,621
Noncontrolling interest5,882
 7,820
Total equity34,151
 26,441
Total liabilities and equity$77,965
 $70,105
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
 Years Ended December 31,
 2017 2016* 2015*
REVENUES:     
Natural gas sales$4,172
 $3,619
 $3,671
NGL sales6,972
 4,841
 3,936
Crude sales10,184
 6,766
 8,378
Gathering, transportation and other fees4,265
 4,003
 3,997
Refined product sales (see Note 3)1,515
 1,047
 9,958
Other (see Note 3)1,946
 1,551
 4,352
Total revenues29,054
 21,827
 34,292
COSTS AND EXPENSES:     
Cost of products sold (see Note 3)20,801
 15,080
 26,714
Operating expenses (see Note 3)2,170
 1,839
 2,608
Depreciation, depletion and amortization2,332
 1,986
 1,929
Selling, general and administrative (see Note 3)434
 348
 475
Impairment losses920
 813
 339
Total costs and expenses26,657
 20,066
 32,065
OPERATING INCOME2,397
 1,761
 2,227
OTHER INCOME (EXPENSE):     
Interest expense, net(1,365) (1,317) (1,291)
Equity in earnings from unconsolidated affiliates156
 59
 469
Impairment of investments in unconsolidated affiliates(313) (308) —
Gains on acquisitions—
 83
 —
Losses on extinguishments of debt(42) —
 (43)
Losses on interest rate derivatives(37) (12) (18)
Other, net209
 131
 22
INCOME BEFORE INCOME TAX BENEFIT1,005
 397
 1,366
Income tax benefit(1,496) (186) (123)
NET INCOME2,501
 583
 1,489
Less: Net income attributable to noncontrolling interest420
 295
 134
Less: Net loss attributable to predecessor—
 —
 (34)
NET INCOME ATTRIBUTABLE TO PARTNERS2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)$986
 $(1,019) $(27)
NET INCOME (LOSS) PER COMMON UNIT:     
Basic$0.94
 $(1.38) $(0.07)
Diluted$0.93
 $(1.38) $(0.08)
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
Net income$2,501
 $583
 $1,489
Other comprehensive income (loss), net of tax:     
Change in value of available-for-sale securities6
 2
 (3)
Actuarial gain (loss) relating to pension and other postretirement benefits(12) (1) 65
Foreign currency translation adjustment—
 (1) (1)
Change in other comprehensive income (loss) from unconsolidated affiliates1
 4
 (1)
 (5) 4
 60
Comprehensive income2,496
 587
 1,549
Less: Comprehensive income attributable to noncontrolling interest420
 295
 134
Less: Comprehensive loss attributable to predecessor—
 —
 (34)
Comprehensive income attributable to partners$2,076
 $292
 $1,449
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
     Limited Partners          
 Series A Preferred Units Series B Preferred Units Common Unit holders Class H Units Class I Units General
Partner		 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-controlling
Interest
 Predecessor Equity Total
Balance, December 31, 2014*$—
 $—
 $10,427
 $1,512
 $—
 $184
 $(56) $5,143
 $8,088
 $25,298
Distributions to partners—
 —
 (1,863) (247) (80) (944) —
 —
 —
 (3,134)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (338) —
 (338)
Units issued for cash—
 —
 1,428
 —
 —
 —
 —
 —
 —
 1,428
Subsidiary units issued for cash—
 —
 298
 —
 —
 2
 —
 1,219
 —
 1,519
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 875
 —
 875
Bakken Pipeline Transaction—
 —
 (999) 1,946
 —
 —
 —
 72
 —
 1,019
Sunoco LP Exchange Transaction—
 —
 (52) —
 —
 —
 —
 (940) —
 (992)
Susser Exchange Transaction—
 —
 (68) —
 —
 —
 —
 —
 —
 (68)
Acquisition and disposition of noncontrolling interest—
 —
 (26) —
 —
 —
 —
 (39) —
 (65)
Predecessor distributions to partners—
 —
 —
 —
 —
 —
 —
 —
 (202) (202)
Predecessor units issued for cash—
 —
 —
 —
 —
 —
 —
 —
 34
 34
Regency Merger—
 —
 7,890
 —
 —
 —
 —
 —
 (7,890) —
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 60
 —
 —
 60
Other, net—
 —
 23
 —
 —
 —
 —
 36
 4
 63
Net income (loss)—
 —
 (27) 258
 94
 1,064
 —
 134
 (34) 1,489
Balance, December 31, 2015*—
 —
 17,031
 3,469
 14
 306
 4
 6,162
 —
 26,986
Distributions to partners—
 —
 (2,134) (340) (20) (1,048) —
 —
 —
 (3,542)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (481) —
 (481)
Units issued for cash—
 —
 1,098
 —
 —
 —
 —
 —
 —
 1,098
Subsidiary units issued—
 —
 37
 —
 —
 —
 —
 1,351
 —
 1,388

Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 236
 —
 236
Sunoco, Inc. retail business to Sunoco LP transaction—
 —
 (405) —
 —
 —
 —
 —
 —
 (405)
PennTex Acquisition—
 —
 307
 —
 —
 —
 —
 236
 —
 543
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 4
 —
 —
 4
Other, net—
 —
 10
 —
 —
 —
 —
 21
 —
 31
Net income (loss)—
 —
 (1,019) 351
 8
 948
 —
 295
 —
 583
Balance, December 31, 2016*—
 —
 14,925
 3,480
 2
 206
 8
 7,820
 —
 26,441
Distributions to partners—
 —
 (2,419) (95) (2) (952) —
 —
 —
 (3,468)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (430) —
 (430)
Units issued for cash937
 542
 2,283
 —
 —
 —
 —
 —
 —
 3,762
Sunoco Logistics Merger—
 —
 9,416
 (3,478) —
 —
 —
 (5,938) —
 —
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 2,202
 —
 2,202
Sale of Bakken Pipeline interest—
 —
 1,260
 —
 —
 —
 —
 740
 —
 2,000
Sale of Rover Pipeline interest—
 —
 93
 —
 —
 —
 —
 1,385
 —
 1,478
Acquisition of PennTex noncontrolling interest—
 —
 (48) —
 —
 —
 —
 (232) —
 (280)
Other comprehensive loss, net of tax—
 —
 —
 —
 —
 —
 (5) —
 —
 (5)
Other, net—
 —
 35
 —
 —
 —
 —
 (85) —
 (50)
Net income7
 5
 986
 93
 —
 990
 —
 420
 —
 2,501
Balance, December 31, 2017$944
 $547
 $26,531
 $—
 $—
 $244
 $3
 $5,882
 $—
 $34,151
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
OPERATING ACTIVITIES:     
Net income$2,501
 $583
 $1,489
Reconciliation of net income to net cash provided by operating activities:     
Depreciation, depletion and amortization2,332
 1,986
 1,929
Deferred income taxes(1,531) (169) 202
Amortization included in interest expense2
 (20) (36)
Inventory valuation adjustments—
 —
 (58)
Unit-based compensation expense74
 80
 79
Impairment losses920
 813
 339
Gains on acquisitions—
 (83) —
Losses on extinguishments of debt42
 —
 43
Impairment of investments in unconsolidated affiliates313
 308
 —
Distributions on unvested awards(31) (25) (16)
Equity in earnings of unconsolidated affiliates(156) (59) (469)
Distributions from unconsolidated affiliates440
 406
 440
Other non-cash(261) (271) (22)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations(160) (246) (1,173)
Net cash provided by operating activities4,485
 3,303
 2,747
INVESTING ACTIVITIES:     
Cash proceeds from sale of Bakken Pipeline interest2,000
 —
 —
Cash proceeds from sale of Rover Pipeline interest1,478
 —
 —
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction—
 2,200
 —
Proceeds from Bakken Pipeline Transaction—
 —
 980
Proceeds from Susser Exchange Transaction—
 —
 967
Proceeds from sale of noncontrolling interest—
 —
 64
Cash paid for acquisition of PennTex noncontrolling interest(280) —
 —
Cash paid for Vitol Acquisition, net of cash received—
 (769) —
Cash paid for PennTex Acquisition, net of cash received—
 (299) —
Cash transferred to ETE in connection with the Sunoco LP Exchange—
 —
 (114)
Cash paid for acquisition of a noncontrolling interest—
 —
 (129)
Cash paid for all other acquisitions(264) (159) (675)
Capital expenditures, excluding allowance for equity funds used during construction(8,335) (7,550) (9,098)
Contributions in aid of construction costs24
 71
 80
Contributions to unconsolidated affiliates(268) (59) (45)
Distributions from unconsolidated affiliates in excess of cumulative earnings136
 135
 124
Proceeds from the sale of assets35
 25
 23
Change in restricted cash—
 14
 19
Other1
 1
 (16)
Net cash used in investing activities(5,473) (6,390) (7,820)
      

FINANCING ACTIVITIES:     
Proceeds from borrowings26,736
 19,916
 22,462
Repayments of long-term debt(26,494) (15,799) (17,843)
Cash (paid to) received from affiliate notes(255) 124
 233
Common Units issued for cash2,283
 1,098
 1,428
Preferred Units issued for cash1,479
 —
 —
Subsidiary units issued for cash—
 1,388
 1,519
Predecessor units issued for cash—
 —
 34
Capital contributions from noncontrolling interest1,214
 236
 841
Distributions to partners(3,468) (3,542) (3,134)
Predecessor distributions to partners—
 —
 (202)
Distributions to noncontrolling interest(430) (481) (338)
Redemption of Legacy ETP Preferred Units(53) —
 —
Debt issuance costs(83) (22) (63)
Other5
 2
 —
Net cash provided by financing activities934
 2,920
 4,937
Decrease in cash and cash equivalents(54) (167) (136)
Cash and cash equivalents, beginning of period360
 527
 663
Cash and cash equivalents, end of period$306
 $360
 $527
* As adjusted. See Note 2.




ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)

1.OPERATIONS AND BASIS OF PRESENTATION:
Organization. The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETP”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner.
In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled.
In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein:
References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;
References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and
References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.
The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes).
The Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales.
The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.
The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.

The Partnership owns a controlling interest in Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the date the financial statements were issued.
For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.
The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, these undivided interests are consolidated proportionately.
2.ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Change in Accounting Policy
During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows:
 Year Ended December 31, 2016 Year Ended December 31, 2015
 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted
Consolidated Statement of Operations and Comprehensive Income:           
Cost of products sold$15,039
 $41
 $15,080
 $26,682
 $32
 $26,714
Operating income1,802
 (41) 1,761
 2,259
 (32) 2,227
Income before income tax benefit438
 (41) 397
 1,398
 (32) 1,366
Net income624
 (41) 583
 1,521
 (32) 1,489
Net income attributable to partners297
 (9) 288
 1,398
 (9) 1,389
Net loss per common unit - basic(1.37) (0.01) (1.38) (0.06) (0.01) (0.07)
Net loss per common unit - diluted(1.37) (0.01) (1.38) (0.07) (0.01) (0.08)
Comprehensive income628
 (41) 587
 1,581
 (32) 1,549
Comprehensive income attributable to partners301
 (9) 292
 1,458
 (9) 1,449
            
Consolidated Statements of Cash Flows:           
Net income624
 (41) 583
 1,521
 (32) 1,489
Net change in operating assets and liabilities (change in inventories)(117) (129) (246) (1,367) 194
 (1,173)
            
Consolidated Balance Sheets (at period end):           
Inventories1,712
 (86) 1,626
 1,213
 (45) 1,168
Total partners' capital18,642
 (21) 18,621
 20,836
 (12) 20,824
* Amounts reflect certain reclassifications made to conform to the current year presentation.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Recent Accounting Pronouncements
ASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.
For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of our midstream segment agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.
ASU 2016-02
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-16
On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.
ASU 2017-12
In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
Revenue Recognition
Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the

pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.
In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and segment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.
In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

Regulatory Accounting – Regulatory Assets and Liabilities
Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:
 Years Ended December 31,
 2017 2016 2015
Accounts receivable$(950) $(919) $819
Accounts receivable from related companies67
 30
 (243)
Inventories37
 (497) (157)
Other current assets39
 83
 (178)
Other non-current assets, net(94) (78) 188
Accounts payable758
 972
 (1,215)
Accounts payable to related companies(3) 29
 (160)
Accrued and other current liabilities(47) 39
 (83)
Other non-current liabilities24
 33
 (219)
Price risk management assets and liabilities, net9
 62
 75
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations$(160) $(246) $(1,173)

Non-cash investing and financing activities and supplemental cash flow information are as follows:
 Years Ended December 31,
 2017 2016 2015
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$1,059
 $822
 $896
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP—
 194
 —
Net gains from subsidiary common unit transactions—
 37
 300
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with the PennTex Acquisition$—
 $307
 $—
Issuance of Common Units in connection with the Regency Merger—
 —
 9,250
Issuance of Class H Units in connection with the Bakken Pipeline Transaction—
 —
 1,946
Contribution of assets from noncontrolling interest988
 —
 34
Redemption of Common Units in connection with the Bakken Pipeline Transaction—
 —
 999
Redemption of Common Units in connection with the Sunoco LP Exchange—
 —
 52
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$1,329
 $1,411
 $1,467
Cash paid for (refund of) income taxes50
 (229) 71
Accounts Receivable
Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.
We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.
We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories
As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017.
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Inventories consisted of the following:
 December 31,
 2017 2016
Natural gas, NGLs, and refined products$733
 $758
Crude oil551
 651
Spare parts and other305
 217
Total inventories$1,589
 $1,626
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Other Current Assets
Other current assets consisted of the following:
 December 31,
 2017 2016
Deposits paid to vendors$64
 $74
Prepaid expenses and other146
 224
Total other current assets$210
 $298
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:
 December 31,
 2017 2016
Land and improvements$1,706
 $676
Buildings and improvements (1 to 45 years)1,960
 1,617
Pipelines and equipment (5 to 83 years)44,050
 36,356
Natural gas and NGL storage facilities (5 to 46 years)1,681
 1,452
Bulk storage, equipment and facilities (2 to 83 years)3,036
 3,701
Vehicles (1 to 25 years)124
 217
Right of way (20 to 83 years)3,424
 3,349
Natural resources434
 434
Other (1 to 40 years)534
 484
Construction work-in-process10,750
 9,934
 67,699
 58,220
Less – Accumulated depreciation and depletion(9,262) (7,303)
Property, plant and equipment, net$58,437
 $50,917
We recognized the following amounts for the periods presented:
 December 31,
 2014 2013
Available-for-sale securities$(1) $(1)
Foreign currency translation adjustment2
 1
Actuarial gain relating to pension and other postretirement benefits(37) (39)
Total$(36) $(39)
 Years Ended December 31,
 2017 2016 2015
Depreciation and depletion expense$2,060
 $1,793
 $1,713
Capitalized interest283
 199
 163
Advances to and Investments in Unconsolidated Affiliates
We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
 December 31,
 2017 2016
Regulatory assets$85
 $86
Deferred charges210
 217
Restricted funds192
 190
Long-term affiliated receivable85
 90
Other186
 89
Total other non-current assets, net$758
 $672
(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.
Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.

Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:
 December 31, 2017 December 31, 2016
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:       
Customer relationships, contracts and agreements (3 to 46 years)$6,250
 $(1,003) $5,362
 $(737)
Patents (10 years)48
 (26) 48
 (21)
Trade Names (20 years)66
 (25) 66
 (22)
Other (5 to 20 years)1
 —
 2
 (2)
Total intangible assets$6,365
 $(1,054) $5,478
 $(782)
Aggregate amortization expense of intangible assets was as follows:
 Years Ended December 31,
 2017 2016 2015
Reported in depreciation, depletion and amortization$272
 $193
 $216
Estimated aggregate amortization expense for the next five years is as follows:
Years Ending December 31: 
2018$280
2019278
2020278
2021268
2022256
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
In 2015, we recorded $24 million of intangible asset impairments related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:
 Intrastate
Transportation
and Storage		 Interstate
Transportation and Storage		 Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services All Other Total
Balance, December 31, 2015$10
 $912
 $718
 $772
 $912
 $2,104
 $5,428
Reduction due to contribution of legacy Sunoco, Inc. retail business—
 —
 —
 —
 —
 (1,289) (1,289)
Acquired—
 —
 177
 —
 251
 —
 428
Impaired—
 (638) (32) —
 —
 —
 (670)
Balance, December 31, 201610
 274
 863
 772
 1,163
 815
 3,897
Acquired—
 —
 8
 —
 4
 —
 12
Impaired—
 (262) —
 (79) —
 (452) (793)
Other—
 —
 (1) —
 —
 —
 (1)
Balance, December 31, 2017$10
 $12
 $870
 $693
 $1,167
 $363
 $3,115
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve.
During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.
The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted

risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Long-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
 December 31,
 2017 2016
Interest payable$443
 $440
Customer advances and deposits59
 56
Accrued capital expenditures1,006
 749
Accrued wages and benefits208
 212
Taxes payable other than income taxes108
 63
Exchanges payable154
 208
Other165
 177
Total accrued and other current liabilities$2,143
 $1,905
Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests
The noncontrolling interest holders in one of our consolidated subsidiaries has the option to sell its interests to us.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheet.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $32.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2017, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016 based on inputs used to derive their fair values:
 Fair Value Total Fair Value Measurements at December 31, 2017
 Level 1 Level 2
Assets:     
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX$11
 $11
 $—
Swing Swaps IFERC13
 —
 13
Fixed Swaps/Futures70
 70
 —
Forward Physical Swaps8
 —
 8
Power:     
Forwards23
 —
 23
Natural Gas Liquids – Forwards/Swaps193
 193
 —
Crude – Futures2
 2
 —
Total commodity derivatives320
 276
 44
Other non-current assets21
 14
 7
Total assets$341
 $290
 $51
Liabilities:     
Interest rate derivatives$(219) $—
 $(219)
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX(24) (24) —
Swing Swaps IFERC(15) (1) (14)
Fixed Swaps/Futures(57) (57) —
Forward Physical Swaps(2) —
 (2)
Power – Forwards(22) —
 (22)
Natural Gas Liquids – Forwards/Swaps(192) (192) —
Refined Products – Futures(25) (25) —
Crude – Futures(1) (1) —
Total commodity derivatives(338) (300) (38)
Total liabilities$(557) $(300) $(257)

 Fair Value Total Fair Value Measurements at December 31, 2016
 Level 1 Level 2 Level 3
Assets:       
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX$14
 $14
 $—
 $—
Swing Swaps IFERC2
 —
 2
 —
Fixed Swaps/Futures96
 96
 —
 —
Forward Physical Swaps1
 —
 1
 —
Power:       
Forwards4
 —
 4
 —
Futures1
 1
 —
 —
Options – Calls1
 1
 —
 —
Natural Gas Liquids – Forwards/Swaps233
 233
 —
 —
Refined Products – Futures1
 1
 —
 —
Crude – Futures9
 9
 —
 —
Total commodity derivatives362
 355
 7
 —
Other non-current assets13
 8
 5
 —
Total assets$375
 $363
 $12
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in the Legacy ETP Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) —
 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids – Forwards/Swaps(273) (273) —
 —
Refined Products – Futures(17) (17) —
 —
Crude – Futures(13) (13) —
 —
Total commodity derivatives(472) (464) (8) —
Total liabilities$(666) $(464) $(201) $(1)
Contributions in Aid of Construction Costs
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs
Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

Costs and Expenses
Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We record the collection of taxes to be remitted to government authorities on a net basis except for our all other segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). For the year ended December 31, 2015, excise taxes collected by Sunoco LP were $1.85 billion. The Partnership deconsolidated Sunoco LP effective July 1, 2015 and no excise taxes were collected by our consolidated operations subsequent to that date.
Issuances of Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Taxes
ETP is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, and 2015, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company and until July 31, 2015, Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Unit-Based Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income
For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for United States Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.


3.ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
2018 Transactions
CDM Contribution Agreement
In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.
In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million.
2017 Transactions
Rover Contribution Agreement
In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.
ETP and Sunoco Logistics Merger
As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger.
Permian Express Partners
In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
2016 Transactions
PennTex Acquisition
On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, the Partnership purchased PennTex’s remaining outstanding common units in June 2017.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The total purchase price was allocated as follows:
  At November 1, 2016
Total current assets $34
Property, plant and equipment 393
Goodwill(1)
 177
Intangible assets 446
  1,050
   
Total current liabilities 6
Long-term debt, less current maturities 164
Other non-current liabilities 17
Noncontrolling interest 236
  423
Total consideration 627
Cash received 21
Total consideration, net of cash received $606
(1)
None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Sunoco Logistics’ Vitol Acquisition
In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to 100%. The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million.

Bakken Financing
In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billion credit facility provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $2.50 billion was outstanding under this credit facility.
Bayou Bridge
In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system.
Sunoco Retail to Sunoco LP
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of $1.29 billion and intangible assets of $294 million. The results of Sunoco, LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.
Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated:
 Year Ended December 31, 2015
Revenues$12,482
Cost of products sold11,174
Operating expenses798
Selling, general and administrative expenses106
2015 Transactions
Sunoco LP
In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015.
In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE provided ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. In connection with this transaction, the Partnership deconsolidated Sunoco LP, including goodwill of $1.81 billion and intangible assets of $982 million related to Sunoco LP. At December 31, 2017, the Partnership held 37.8 million Sunoco LP common units accounted for under the equity method. Subsequent to Sunoco LP’s

repurchase of a portion of its common units on February 7, 2018, as discussed in Note 4, our investment in Sunoco LP consists of 26.2 million units. The results of Sunoco LP’s operations have not been presented as discontinued operations and Sunoco LP’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.
Bakken Pipeline
In March 2015, ETE transferred 46.2 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017.
In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.
Regency Merger
On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 Partnership common units. ETP issued 258.3 million Partnership common units to Regency unitholders, including 23.3 million units issued to Partnership subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding Legacy ETP Preferred Units on a one-for-one basis.
In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.
The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger.
ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.

4.ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
Citrus
ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, an approximately 5,360-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment.
FEP
We have a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. The Partnership recorded an impairment of its investment

in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor.
MEP
We own a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016.
HPC
We own a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Our investment in HPC is reflected in the intrastate transportation and storage segment. The Partnership evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, the Partnership recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.
Sunoco LP
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from the Partnership. As a result, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. As of December 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units, and is reflected in the all other segment.
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.
The carrying values of the Partnership’s advances to and investments in unconsolidated affiliates as of December 31, 2017 and 2016 were as follows:
 December 31,
 2017 2016
Citrus$1,754
 $1,729
FEP121
 101
MEP242
 318
HPC28
 382
Sunoco LP1,095
 1,225
Others576
 525
Total$3,816
 $4,280

The following table presents equity in earnings (losses) of unconsolidated affiliates:
 Years Ended December 31,
 2017 2016 2015
Citrus$144
 $102
 $97
FEP53
 51
 55
MEP38
 40
 45
HPC(1)
(168) 31
 32
Sunoco, LLC—
 —
 (10)
Sunoco LP(2)
12
 (211) 202
Other77
 46
 48
Total equity in earnings of unconsolidated affiliates156
 59
 469
(1)
For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
(2)
For the years ended December 31, 2017 and 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million, respectively.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, HPC and Sunoco LP (on a 100% basis) for all periods presented:
 December 31,
 2017 2016
Current assets$4,750
 $1,532
Property, plant and equipment, net9,893
 10,310
Other assets2,286
 5,980
Total assets$16,929
 $17,822
    
Current liabilities$2,075
 $1,918
Non-current liabilities9,375
 10,343
Equity5,479
 5,561
Total liabilities and equity$16,929
 $17,822
 Years Ended December 31,
 2017 2016 2015
Revenue$13,081
 $11,150
 $13,815
Operating income636
 859
 1,052
Net income (loss)294
 (22) 664
In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.


5.NET INCOME (LOSS) PER LIMITED PARTNER UNIT:
The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
 Years Ended December 31,
 2017 2016 2015
Net income$2,501
 $583
 $1,489
Less: Income attributable to noncontrolling interest420
 295
 134
Less: Loss attributable to predecessor—
 —
 (34)
Net income, net of noncontrolling interest2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)986
 (1,019) (27)
Additional earnings allocated from (to) General Partner9
 (10) (5)
Distributions on employee unit awards, net of allocation to General Partner(27) (19) (16)
Net income (loss) available to Common Unitholders$968
 $(1,048) $(48)
Weighted average Common Units – basic1,032.7
 758.2
 649.2
Basic net income (loss) per Common Unit$0.94
 $(1.38) $(0.07)
      
Income (loss) available to Common Unitholders$968
 $(1,048) $(48)
Loss attributable to Legacy ETP Preferred Units—
 —
 (6)
Diluted income (loss) available to Common Unitholders$968
 $(1,048) $(54)
Weighted average Common Units – basic1,032.7
 758.2
 649.2
Dilutive effect of unvested Unit Awards5.1
 —
 —
Dilutive effect of Legacy ETP Preferred Units—
 —
 1.0
Weighted average Common Units – diluted1,037.8
 758.2
 650.2
Diluted income (loss) per Common Unit$0.93
 $(1.38) $(0.08)

6.DEBT OBLIGATIONS:
Our debt obligations consist of the following:
 December 31,
 2017 2016
ETP Debt   
6.125% Senior Notes due February 15, 2017$—
 $400
2.50% Senior Notes due June 15, 2018 (1)650
 650
6.70% Senior Notes due July 1, 2018 (1)600
 600
9.70% Senior Notes due March 15, 2019400
 400
9.00% Senior Notes due April 15, 2019450
 450
5.50% Senior Notes due February 15, 2020250
 250
5.75% Senior Notes due September 1, 2020400
 400

4.15% Senior Notes due October 1, 20201,050
 1,050
4.40% Senior Notes due April 1, 2021600
 600
6.50% Senior Notes due July 15, 2021—
 500
4.65% Senior Notes due June 1, 2021800
 800
5.20% Senior Notes due February 1, 20221,000
 1,000
4.65% Senior Notes due February 15, 2022300
 300
5.875% Senior Notes due March 1, 2022900
 900
5.00% Senior Notes due October 1, 2022700
 700
3.45% Senior Notes due January 15, 2023350
 350
3.60% Senior Notes due February 1, 2023800
 800
5.50% Senior Notes due April 15, 2023—
 700
4.50% Senior Notes due November 1, 2023600
 600
4.90% Senior Notes due February 1, 2024350
 350
7.60% Senior Notes due February 1, 2024277
 277
4.25% Senior Notes due April 1, 2024500
 500
9.00% Debentures due November 1, 202465
 65
4.05% Senior Notes due March 15, 20251,000
 1,000
5.95% Senior Notes due December 1, 2025400
 400
4.75% Senior Notes due January 15, 20261,000
 1,000
3.90% Senior Notes due July 15, 2026550
 550
4.20% Senior Notes due April 15, 2027600
 —
4.00% Senior Notes due October 1, 2027750
 —
8.25% Senior Notes due November 15, 2029267
 267
4.90% Senior Notes due March 15, 2035500
 500
6.625% Senior Notes due October 15, 2036400
 400
7.50% Senior Notes due July 1, 2038550
 550
6.85% Senior Notes due February 15, 2040250
 250
6.05% Senior Notes due June 1, 2041700
 700
6.50% Senior Notes due February 1, 20421,000
 1,000
6.10% Senior Notes due February 15, 2042300
 300
4.95% Senior Notes due January 15, 2043350
 350
5.15% Senior Notes due February 1, 2043450
 450
5.95% Senior Notes due October 1, 2043450
 450
5.30% Senior Notes due April 1, 2044700
 700
5.15% Senior Notes due March 15, 20451,000
 1,000
5.35% Senior Notes due May 15, 2045800
 800
6.125% Senior Notes due December 15, 20451,000
 1,000
5.30% Senior Notes due April 15, 2047900
 —
5.40% Senior Notes due October 1, 20471,500
 —
Floating Rate Junior Subordinated Notes due November 1, 2066546
 546
ETP $4.0 billion Revolving Credit Facility due December 20222,292
 —
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)50
 —
ETLP $3.75 billion Revolving Credit Facility due November 2019—
 2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020—
 1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017—
 630
Unamortized premiums, discounts and fair value adjustments, net33
 66
Deferred debt issuance costs(170) (166)
 29,210
 29,454
Transwestern Debt   
5.64% Senior Notes due May 24, 2017—
 82
5.36% Senior Notes due December 9, 2020175
 175
5.89% Senior Notes due May 24, 2022150
 150
5.66% Senior Notes due December 9, 2024175
 175
6.16% Senior Notes due May 24, 203775
 75
Deferred debt issuance costs(1) (1)
 574
 656
Panhandle Debt   
6.20% Senior Notes due November 1, 2017—
 300

7.00% Senior Notes due June 15, 2018400
 400
8.125% Senior Notes due June 1, 2019150
 150
7.60% Senior Notes due February 1, 202482
 82
7.00% Senior Notes due July 15, 202966
 66
8.25% Senior Notes due November 15, 202933
 33
Floating Rate Junior Subordinated Notes due November 1, 206654
 54
Unamortized premiums, discounts and fair value adjustments, net28
 50
 813
 1,135
Sunoco, Inc. Debt   
5.75% Senior Notes due January 15, 2017—
 400
    
Bakken Project Debt   
Bakken Project $2.50 billion Credit Facility due August 20192,500
 1,100
Deferred debt issuance costs(8) (13)
 2,492
 1,087
PennTex Debt   
PennTex $275 million Revolving Credit Facility due December 2019—
 168
    
Other5
 30
 33,094
 32,930
Less: Current maturities of long-term debt407
 1,189
 $32,687
 $31,741
(1)
As of December 31, 2017 management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.
(2)
Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs:
2018 $1,700
2019 3,500
2020 1,875
2021 1,400
2022 5,346
Thereafter 19,391
Total $33,212
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
ETP Senior Notes
The ETP senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.
The ETP senior notes are unsecured obligations of the Partnership and as a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

Transwestern Senior Notes
The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017.
Credit Facilities and Commercial Paper
ETP Credit Facilities
On December 1, 2017 the Partnership entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).  The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to $6.0 billion under certain conditions. We use the ETP Credit Facilities to provide temporary financing for our growth projects, as well as for general partnership purposes.
As of December 31, 2017, the ETP Five-Year Facility had $2.29 billion outstanding, of which $2.01 billion was commercial paper. The amount available for future borrowings was $1.56 billion after taking into account letters of credit of $150 million. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 2.48%.
As of December 31, 2017, the ETP 364-Day Facility had $50 million outstanding, and the amount available for future borrowings was $950 million. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 5.00%.
ETLP Credit Facility
The ETLP Credit Facility allowed for borrowings of up to $3.75 billion and was used to provide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.
Sunoco Logistics Credit Facilities
ETP maintained a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.
In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2017, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%.
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

Covenants Related to Our Credit Agreements
Covenants Related to ETP
The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The ETP Credit Facilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
incur indebtedness;
grant liens;
enter into mergers;
dispose of assets;
make certain investments;
make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities);
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
engage in transactions with affiliates; and
enter into restrictive agreements.
The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from 0.125% to 0.300%.  The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225%.
The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as calculated in accordance with the credit agreements.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-

acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.
In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Bakken Credit Facility
The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:
prohibition of certain incremental secured indebtedness;
prohibition of certain liens / negative pledge;
limitations on uses of loan proceeds;
limitations on asset sales and purchases;
limitations on permitted business activities;
limitations on mergers and acquisitions;
limitations on investments;
limitations on transactions with affiliates; and
maintenance of commercially reasonable insurance coverage.
A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.
Compliance with our Covenants
We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.

7.LEGACY ETP PREFERRED UNITS:
The Legacy ETP Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and were reflected as long-term liabilities in our consolidated balance sheets. The Legacy ETP Preferred Units were entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record dates of the Partnership’s common unit distributions. In January 2017, ETP repurchased all of its 1.9 million outstanding Legacy ETP Preferred Units for cash in the aggregate amount of $53 million.

8.EQUITY:
Limited Partner interests are represented by Common, Class E Units, Class G Units, Class I Units, Class J Units and Class K Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s outstanding securities also include preferred units, as described below. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance.

IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs.
Common Units
The change in Common Units was as follows:
 Years Ended December 31,
 
2017 (1)
 
2016 (1)
 
2015 (1)
Number of Common Units, beginning of period794.8
 758.5
 533.4
Common Units redeemed in connection with certain transactions—
 (26.7) (77.8)
Common Units issued in connection with public offerings54.0
 —
 —
Common Units issued in connection with certain acquisitions—
 13.3
 258.2
Common Units issued in connection with the Distribution Reinvestment Plan12.0
 9.9
 11.7
Common Units issued in connection with Equity Distribution Agreements22.6
 39.0
 31.7
Common Units issued to ETE in a private placement transaction23.7
 —
 —
Common Unit increase from Sunoco Logistics Merger (2)255.4
 —
 —
Issuance of Common Units under equity incentive plans1.6
 0.8
 1.3
Number of Common Units, end of period1,164.1
 794.8
 758.5
(1)
The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
(2)
Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.
Our Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”
Equity Distribution Program
From time to time, we have sold Common Units through equity distribution agreements. Such sales of Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreements.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion.
During the year ended December 31, 2017, we issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $752 million of our Common Units remained available to be issued under our currently effective equity distribution agreement.
Equity Incentive Plan Activity
We issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.

Distribution Reinvestment Program
Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, the Partnership initiated a new distribution reinvestment plan.
During the years ended December 31, 2017, 2016 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units.
As of December 31, 2017, a total of 20.8 million Common Units remain available to be issued under the existing registration statement.
August 2017 Units Offering
In August 2017, the Partnership issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by the Partnership to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.
January 2017 Private Placement
In January 2017, the Partnership sold 23.7 million ETP Common Units to ETE in a private placement transaction for gross proceeds of approximately $568 million.
Class E Units
There are currently 8.9 million Class E Units outstanding, all of which are currently owned by HHI. The Class E Units generally do not have any voting rights. The Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the Class E Units at a future date.
Class G Units
There are currently 90.7 million Class G Units outstanding, all of which are held by a wholly-owned subsidiary of the Partnership. The Class G Units generally do not have any voting rights. The Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class G Unit per year. Allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are reflected as treasury units in the consolidated financial statements.
Class H Units
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.
Class I Units
In connection with the Bakken Pipeline Transaction discussed in Note 3, in April 2015, ETP issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the

cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
Class K Units
On December 29, 2016, the Partnership issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in the Partnership, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco.  If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2017, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETP.
Sales of Common Units by legacy Sunoco Logistics
Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.
In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated.
ETP Preferred Units
In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit.
Distributions on the Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation

preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.
Quarterly Distributions of Available Cash
Under the Partnership’s limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”
The following table shows the target distribution levels and distribution “splits” between the general and limited partners and the holders of the Partnership’s incentive distribution rights (”IDRs”):
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount IDRs 
Partners (1)
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%
(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:
Quarter Ended ETP Sunoco Logistics
December 31, 2014 $0.6633
 $0.4000
March 31, 2015 0.6767
 0.4190
June 30, 2015 0.6900
 0.4380
September 30, 2015 0.7033
 0.4580
December 31, 2015 0.7033
 0.4790
March 31, 2016 0.7033
 0.4890
June 30, 2016 0.7033
 0.5000
September 30, 2016 0.7033
 0.5100
December 31, 2016 0.7033
 0.5200

Distributions on common units declared and paid by Post-Merger ETP were as follows:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 16, 2017 $0.5350
June 30, 2017 August 7, 2017 August 15, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
December 31, 2017 February 8, 2018 February 14, 2018 0.5650
In connection with previous transactions, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods:
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Distributions declared and paid by ETP to the preferred unitholders were as follows:
 Distribution per Preferred Unit
Quarter Ended Record Date Payment Date Series A Series B
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
 $16.378
Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
 December 31,
 2017 2016
Available-for-sale securities$8
 $2
Foreign currency translation adjustment(5) (5)
Actuarial gain related to pensions and other postretirement benefits(5) 7
Investments in unconsolidated affiliates, net5
 4
Total AOCI, net of tax$3
 $8
The table below sets forth the tax amounts included in the respective components of other comprehensive income:
 December 31,
 2017 2016
Available-for-sale securities$(2) $(2)
Foreign currency translation adjustment3
 3
Actuarial loss relating to pension and other postretirement benefits3
 —
Total$4
 $1

9.UNIT-BASED COMPENSATION PLANS:
ETP Unit-Based Compensation Plan
We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent

rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2014,2017, an aggregate total of 5.48.4 million ETP Common Units remain available to be awarded under our equity incentive plans.
Restricted UnitsPension and Other Postretirement Benefit Plans
We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement.Panhandle
The following table shows the activity of the awards granted to employees and non-employee directors:
 Number of Units Weighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 20133.2
 $49.65
Awards granted1.0
 60.85
Awards vested(0.5) 48.12
Awards forfeited(0.1) 32.36
Unvested awards as of December 31, 20143.6
 53.83
DuringPostretirement benefits expense for the years ended December 31, 2017, 2016, and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, 2013retiree medical benefits were no longer offered to union employees.
Sunoco, Inc.
Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.
Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the weighted average grant-date fair value per unit award grantedtrust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.

The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
 December 31, 2017 December 31, 2016
 Pension Benefits   Pension Benefits  
 Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Change in benefit obligation:           
Benefit obligation at beginning of period$18
 $51
 $166
 $20
 $57
 $181
Interest cost1
 1
 4
 1
 2
 4
Amendments—
 —
 7
 —
 —
 —
Benefits paid, net(2) (6) (20) (1) (7) (21)
Actuarial (gain) loss and other2
 1
 (1) (2) (1) 2
Settlements(18) —
 —
 —
 —
 —
Benefit obligation at end of period$1
 $47
 $156
 $18
 $51
 $166
            
Change in plan assets:           
Fair value of plan assets at beginning of period$12
 $—
 $256
 $15
 $—
 $261
Return on plan assets and other3
 —
 11
 (2) —
 6
Employer contributions6
 —
 10
 —
 —
 10
Benefits paid, net(2) —
 (20) (1) —
 (21)
Settlements(18) —
 —
 —
 —
 —
Fair value of plan assets at end of period$1
 $—
 $257
 $12
 $—
 $256
            
Amount underfunded (overfunded) at end of period$—
 $47
 $(101) $6
 $51
 $(90)
            
Amounts recognized in the consolidated balance sheets consist of:           
Non-current assets$—
 $—
 $127
 $—
 $—
 $114
Current liabilities—
 (8) (2) —
 (7) (2)
Non-current liabilities—
 (39) (24) (6) (44) (23)
 $—
 $(47) $101
 $(6) $(51) $89
            
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:           
Net actuarial gain$—
 $5
 $(18) $—
 $—
 $(13)
Prior service cost—
 —
 21
 —
 —
 15
 $—
 $5
 $3
 $—
 $—
 $2

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
 December 31, 2017 December 31, 2016
 Pension Benefits   Pension Benefits  
 Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Projected benefit obligation$1
 $47
 N/A
 $18
 $51
 N/A
Accumulated benefit obligation1
 47
 $156
 18
 51
 $166
Fair value of plan assets1
 —
 257
 12
 —
 256
Components of Net Periodic Benefit Cost
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Net Periodic Benefit Cost:       
Interest cost$2
 $4
 $3
 $4
Expected return on plan assets—
 (9) (1) (8)
Prior service cost amortization—
 2
 —
 1
Net periodic benefit cost$2
 $(3) $2
 $(3)
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.27% 2.34% 3.65% 2.34%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.52% 3.10% 3.60% 3.06%
Expected return on assets:       
Tax exempt accounts3.50% 7.00% 3.50% 7.00%
Taxable accountsN/A
 4.50% N/A
 4.50%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
The long-term expected rate of return on plan assets was $60.85, $50.54estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and $43.93, respectively. expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest

rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:
 December 31,
 2017 2016
Health care cost trend rate7.20% 6.73%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)4.99% 4.96%
Year that the rate reaches the ultimate trend rate2023
 2021
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%. 
The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.
The fair value of awards vested was $26 million, $29 million and $29 million, respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2014, a total of 3.6 million unit awards remain unvested, for which ETP expects to recognize a total of $128 million in compensation expense over a weighted average period of 2.0 years.
Cash Restricted Units. The Partnership has also granted cash restricted units, which vest 100%pension plan assets by asset category at the end of the third year of service. A cash restricted unit entitles the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting.dates indicated is as follows:
As of December 31, 2014, a total of 0.4 million unvested cash restricted units were outstanding.
Based on the trading price of ETP Common Units at December 31, 2014, the Partnership expects to recognize $24 million of unit-based compensation expense related to non-vested cash restricted units over a period of 1.8 years.

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Sunoco Logistics Unit-Based Compensation Plan
Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units and unit options of Sunoco Logistics covering an additional 0.7 million Sunoco Logistics common units. As of December 31, 2014, a total of 1.5 million Sunoco Logistics restricted units were outstanding for which Sunoco Logistics expects to recognize $33 million of expense over a weighted average period of 2.9 years.
    Fair Value Measurements at December 31, 2017
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Mutual funds (1)
 $1
 $1
 $—
 $—
Total $1
 $1
 $—
 $—
10.
(1)
INCOME TAXES:Comprised of 100% equities as of December 31, 2017.
As a partnership, we are not subject to U.S. federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows:
 Years Ended December 31,
 2014 2013 2012
Current expense (benefit):     
Federal$321
 $51
 $(3)
State81
 (2) 4
Total402
 49
 1
Deferred expense (benefit):     
Federal(50) (6) 45
State3
 54
 17
Total(47) 48
 62
Total income tax expense from continuing operations$355
 $97
 $63
Historically, our effective rate differed from the statutory rate primarily due to Partnership earnings that are not subject to U.S. federal and most state income taxes at the Partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S. statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 2014 and 2013 is as follows:
 December 31, 2014 December 31, 2013
 
Corporate Subsidiaries(1)
 
Partnership(2)
 Consolidated 
Corporate Subsidiaries(1)
 
Partnership(2)
 Consolidated
Income tax expense (benefit) at U.S. statutory rate of 35 percent$217
 $—
 $217
 $(166) $—
 $(166)
Increase (reduction) in income taxes resulting from:    

      
Nondeductible goodwill—
 —
 —
 241
 —
 241
Nondeductible goodwill included in the Lake Charles LNG Transaction105
 —
 105
 —
 —
 —
State income taxes (net of federal income tax effects)9
 42
 51
 31
 5
 36
Premium on debt retirement(10) —
 (10) —
 —
 —
Foreign(8) —
 (8) —
 —
 —
Other—
 —
 —
 (13) (1) (14)
Income tax from continuing operations$313

$42
 $355
 $93
 $4
 $97
    Fair Value Measurements at December 31, 2016
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Mutual funds (1)
 $12
 $12
 $—
 $—
Total $12
 $12
 $—
 $—
(1) 
Includes ETP Holdco, Susser, Oasis Pipeline Company, Susser Petroleum Property Company LLC, Aloha Petroleum Ltd., Inland Corporation, Mid-Valley Pipeline Company and West Texas Gulf Pipeline Company. ETP Holdco, which was formed via the Sunoco Merger and the ETP Holdco Transaction (see Note 3), includes Sunoco, Inc. and Panhandle. ETE held a 60% interest in ETP Holdco until April 30, 2013. Subsequent to the ETP Holdco Acquisition (see Note 3) on April 30, 2013, ETP ownsComprised of 100% equities as of ETP Holdco.December 31, 2016.

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
    Fair Value Measurements at December 31, 2017
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $33
 $33
 $—
 $—
Mutual funds (1)
 154
 154
 —
 —
Fixed income securities 70
 —
 70
 —
Total $257
 $187
 $70
 $—
(2)(1)
Includes ETPPrimarily comprised of approximately 38% equities, 61% fixed income securities and its subsidiaries that are classified2% cash as pass-through entities for federal income tax purposes.of December 31, 2017.

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Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
 December 31,
 2014 2013
Deferred income tax assets:   
Net operating losses and alternative minimum tax credit$116
 $217
Pension and other postretirement benefits47
 57
Long term debt53
 108
Other111
 104
Total deferred income tax assets327
 486
Valuation allowance(84) (74)
Net deferred income tax assets$243
 $412
    
Deferred income tax liabilities:   
Properties, plants and equipment$(1,486) $(1,522)
Inventory(153) (302)
Investment in unconsolidated affiliates(2,528) (2,244)
Trademarks(355) (180)
Other(32) (45)
Total deferred income tax liabilities(4,554) (4,293)
Net deferred income tax liability(4,311) (3,881)
Less: current portion of deferred income tax liabilities, net(85) (119)
Accumulated deferred income taxes$(4,226) $(3,762)
The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3) significantly increased the deferred tax assets (liabilities). The table below provides a rollforward of the net deferred income tax liability as follows:
 December 31,
 2014 2013
Net deferred income tax liability, beginning of year$(3,881) $(3,606)
Susser acquisition(488) —
SUGS Contribution to Regency—
 (115)
Tax provision (including discontinued operations)58
 (111)
Other—
 (49)
Net deferred income tax liability$(4,311) $(3,881)
ETP Holdco, Susser and other corporate subsidiaries have gross federal net operating loss carryforwards of $5 million, all of which will expire in 2032 and 2033. Our corporate subsidiaries had less than $1 million of federal alternative minimum tax credits at December 31, 2014. Our corporate subsidiaries have state net operating loss carryforward benefits of $111 million, net of federal tax, which expire between 2014 and 2033. The valuation allowance of $84 million is applicable to the state net operating loss carryforward benefits applicable to Sunoco, Inc. pre-acquisition periods.

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The following table sets forth the changes in unrecognized tax benefits:
 Years Ended December 31,
 2014 2013 2012
Balance at beginning of year$429
 $27
 $2
Additions attributable to acquisitions—
 —
 28
Additions attributable to tax positions taken in the current year20
 —
 —
Additions attributable to tax positions taken in prior years(1) 406
 —
Settlements(5) —
 —
Lapse of statute(3) (4) (3)
Balance at end of year$440
 $429
 $27
As of December 31, 2014, we have $439 million ($425 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $4 million ($2 million, net of federal tax) within the next twelve months due to settlement of certain positions.
Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 open statute years, Sunoco, Inc. has proposed to the IRS that these government incentive payments be excluded from federal taxable income. If Sunoco, Inc. is fully successful with its claims, it will receive tax refunds of approximately $372 million. However, due to the uncertainty surrounding the claims, a reserve of $372 million was established for the full amount of the claims. Due to the timing of the expected settlement of the claims and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 2014.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2014, we recognized interest and penalties of less than $1 million. At December 31, 2014, we have interest and penalties accrued of $6 million, net of tax.
In general, ETP and its subsidiaries are no longer subject to examination by the IRS for the 2010 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007 and Southern Union and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2004.
Sunoco, Inc. has been examined by the IRS for tax years through 2012. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments. Southern Union is under examination for the tax years 2004 through 2009. As of December 31, 2014, the IRS has proposed only one adjustment for the years under examination. For the 2006 tax year, the IRS is challenging $545 million of the $690 million of deferred gain associated with a like kind exchange involving certain assets of its distribution operations and its gathering and processing operations. We have vigorously defended this tax position and believe we have reached a tentative settlement with the IRS which will not have a material impact on our consolidated financial position or results of operations.
ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.
11.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Contingent Matters Potentially Impacting the Partnership from Our Investment in Citrus
Florida Gas Pipeline Relocation Costs. The Florida Department of Transportation, Florida’s Turnpike Enterprise (“FDOT/FTE”) has various turnpike/State Road 91 widening projects that have impacted or may, over time, impact one or more of FGTs’ mainline pipelines located in FDOT/FTE rights-of-way. Certain FDOT/FTE projects have been or are the subject of litigation in Broward County, Florida. On November 16, 2012, FDOT paid to FGT the sum of approximately $100 million, representing the amount of the judgment, plus interest, in a case tried in 2011.

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On April 14, 2011, FGT filed suit against the FDOT/FTE and other defendants in Broward County, Florida seeking an injunction and damages as the result of the construction of a mechanically stabilized earth wall and other encroachments in FGT easements as part of FDOT/FTE’s I-595 project. On August 21, 2013, FGT and FDOT/FTE entered into a settlement agreement pursuant to which, among other things, FDOT/FTE paid FGT approximately $19 million in September 2013 in settlement of FGT’s claims with respect to the I-595 project. The settlement agreement also provided for agreed easement widths for FDOT/FTE right-of-way and for cost sharing between FGT and FDOT/FTE for any future relocations. Also in September 2013, FDOT/FTE paid FGT an additional approximate $1 million for costs related to the aforementioned turnpike/State Road 91 case tried in 2011.
FGT will continue to seek rate recovery in the future for these types of costs to the extent not reimbursed by the FDOT/FTE. There can be no assurance that FGT will be successful in obtaining complete reimbursement for any such relocation costs from the FDOT/FTE or from its customers or that the timing of such reimbursement will fully compensate FGT for its costs.
Contingent Residual Support Agreement – AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to provide contingent, residual support of $1.55 billion of intercompany borrowings made by AmeriGas and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third party purchases.
PEPL Holdings Guarantee of Collection
In connection with the SUGS Contribution, Regency issued $600 million of 4.50% senior notes due 2023(the “Regency Debt”), the proceeds of which were used by Regency to fund the cash portion of the consideration, as adjusted, and pay certain other expenses or disbursements directly related to the closing of the SUGS Contribution. In connection with the closing of the SUGS Contribution on April 30, 2013, Regency entered into an agreement with PEPL Holdings, a subsidiary of Southern Union, pursuant to which PEPL Holdings provided a guarantee of collection (on a nonrecourse basis to Southern Union) to Regency and Regency Energy Finance Corp. with respect to the payment of the principal amount of the Regency Debt through maturity in 2023. In connection with the completion of the Panhandle Merger, in which PEPL Holdings was merged with and into Panhandle, the guarantee of collection for the Regency Debt was assumed by Panhandle.
NGL Pipeline Regulation
We have interests in NGL pipelines located in Texas and New Mexico. We commenced the interstate transportation of NGLs in 2013, which is subject to the jurisdiction of the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.
Transwestern Rate Case
On October 1, 2014, Transwestern filed a general NGA Section 4 rate case pursuant to the 2011 settlement agreement with its shippers. On December 2, 2014, the FERC issued an order accepting and suspending the rates to be effective April 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in August 2015.
FGT Rate Case
On October 31, 2014, FGT filed a general NGA Section 4 rate case pursuant to a 2010 settlement agreement with its shippers. On November 28, 2014, the FERC issued an order accepting and suspending the rates to be effective May 1, 2015, subject to refund, and setting a procedural schedule with a hearing scheduled in late 2015.
Commitments
In the normal course of our business, we purchase, process and sell natural gas pursuant to long-term contracts and we enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

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We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2058. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
  Years Ended December 31,
  2014 2013 2012
Rental expense(1)
 $139
 $140
 $57
Less: Sublease rental income (26) (24) (4)
Rental expense, net $113
 $116
 $53
    Fair Value Measurements at December 31, 2016
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $23
 $23
 $—
 $—
Mutual funds (1)
 142
 142
 —
 —
Fixed income securities 91
 —
 91
 —
Total $256
 $165
 $91
 $—
(1) 
Includes contingent rentals totaling $24 million, $22 million
Primarily comprised of approximately 31% equities, 66% fixed income securities and $6 million for the years ended3% cash as of December 31, 2014, 2013 and 2012, respectively.2016.
Future minimum lease commitmentsThe Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  
Contributions
We expect to contribute $8 million to pension plans and $10 million to other postretirement plans in 2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for such leases are:income tax purposes.
Benefit Payments
Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:
Years Ending December 31: 
2015$146
2016124
2017114
2018105
2019100
Thereafter803
Future minimum lease commitments1,392
Less: Sublease rental income(34)
Net future minimum lease commitments$1,358
Years 
Pension Benefits - Unfunded Plans (1)
 Other Postretirement Benefits (Gross, Before Medicare Part D)
2018 $8
 $24
2019 6
 23
2020 6
 21
2021 5
 19
2022 4
 17
2023 – 2027 15
 37
Our joint venture agreements require that we fund our proportionate share(1)     Expected benefit payments of capital contributions to our unconsolidated affiliates. Such contributions will depend upon our unconsolidated affiliates’ capital requirements, suchfunded pension plans are less than $1 million for the next ten years.
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as for funding capital projects or repayment of long-term obligations.
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or namedwell as a defendantfederal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Panhandle does not expect to receive any Medicare Part D subsidies in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.any future periods.
MTBE Litigation
14.RELATED PARTY TRANSACTIONS:
Sunoco, Inc., along with other refiners, manufacturers and sellers of gasoline, is a defendant in lawsuits alleging MTBE contamination of groundwater. The plaintiffs typically include water purveyors and municipalities responsible for supplying drinking water and governmental authorities. The plaintiffs are asserting primarily product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. The plaintiffs inIn June 2017, ETP acquired all of the cases are seeking to recover compensatory damages,publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in some cases also seek natural resource damages, injunctive relief, punitive damages and attorneys’ fees.Note 8.
As of December 31, 2014, Sunoco, Inc. is a defendant in five cases, including cases initiated by the States of New Jersey, Vermont, the Commonwealth of Pennsylvania, and two others by the Commonwealth of Puerto Rico with the more recent Puerto Rico action being a companion case alleging damages for additional sites beyond those at issue in the initial Puerto

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Rico action. Four of these cases are venued in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims.
Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. Insufficient information has been developed about the plaintiffs’ legal theories or the facts with respect to statewide natural resource damage claimsETE previously paid ETP to provide an analysis of the ultimate potential liability of Sunoco, Inc. in these matters. It is reasonably possible that a loss may be realized; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that an adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any said adverse determination occurs, but does not believe that any such adverse determination would have a material adverse effect on the Partnership’s consolidated financial position.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recoveryservices on its counterclaims.  Enterprise has filed a noticebehalf and on behalf of appeal. other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016.
In accordanceaddition, subsidiaries of ETE recorded sales with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.
Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For eachaffiliates of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2014 and 2013, accruals of approximately $37$303 million, $221 million and $46$290 million respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
No amounts have been recorded in our December 31, 2014 or 2013 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Attorney General of the Commonwealth of Massachusetts v. New England Gas Company
On July 7, 2011, the Massachusetts Attorney General (“AG”) filed a regulatory complaint with the Massachusetts Department of Public Utilities (“MDPU”) against New England Gas Company with respect to certain environmental cost recoveries.  The AG is seeking a refund to New England Gas Company customers for alleged “excessive and imprudently incurred costs” related to legal fees associated with Southern Union’s environmental response activities.  In the complaint, the AG requests that the MDPU initiate an investigation into the New England Gas Company’s collection and reconciliation of recoverable environmental costs including:  (i) the prudence of any and all legal fees, totaling approximately $19 million, that were charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005, the year when a partner in the firm, the Southern Union former Vice Chairman, President and Chief Operating Officer, joined Southern Union’s management team; (ii) the prudence of any and all legal fees that were charged by the Bishop, London & Dodds firm and passed through the recovery mechanism since 2005, the period during which a member of the firm served as Southern Union’s Chief Ethics Officer; and (iii) the propriety and allocation of certain legal fees charged that were passed through the recovery mechanism that the AG contends only qualify for a lesser, 50%, level of recovery.  Southern Union has filed its answer denying the allegations and moved to dismiss the complaint, in part on a theory of collateral estoppel.  The hearing officer has deferred consideration of Southern Union’s motion to dismiss.  The AG’s motion to be reimbursed expert and consultant costs by Southern Union of up to $150,000 was granted. By tariff, these costs are recoverable through rates charged to New England Gas Company customers. The hearing officer previously stayed discovery pending resolution of a dispute concerning the

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applicability of attorney-client privilege to legal billing invoices. The MDPU issued an interlocutory order on June 24, 2013 that lifted the stay, and discovery has resumed. Panhandle (as successor to Southern Union) believes it has complied with all applicable requirements regarding its filings for cost recovery and has not recorded any accrued liability; however, Panhandle will continue to assess its potential exposure for such cost recoveries as the matter progresses.
Environmental Matters
Our operations are subject to extensive federal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the business of transporting, storing, gathering, treating, compressing, blending and processing natural gas, natural gas liquids and other products. As a result, there can be no assurance that significant costs and liabilities will not be incurred. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the issuance of injunctions and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Currently operating Sunoco, Inc. retail sites.
Legacy sites related to Sunoco, Inc., that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2014, Sunoco, Inc. had been named as a PRP at approximately 51 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.

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The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
 December 31,
 2014 2013
Current$39
 $45
Non-current352
 350
Total environmental liabilities$391
 $395
In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the years ended December 31, 20142017, 2016 and 2013, Sunoco, Inc. had $46 million and $36 million, respectively, of expenditures related to environmental cleanup programs.2015, respectively.
On June 29, 2011, the U.S. Environmental Protection Agency finalized a rule under the Clean Air Act that revised the new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The rule became effective on August 29, 2011. The rule modifications may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment, if we replace equipment or expand existing facilities in the future. At this point, we are not able to predict the cost to comply with the rule’s requirements, because the rule applies only to changes we might make in the future.
Our pipeline operations are subject to regulation by the U.S. Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
Our operations are also subject to the requirements of the OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
12.15.PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:REPORTABLE SEGMENTS:
Commodity Price RiskSubsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.
We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.
Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

Eliminations in the tables below include the following:
MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above.
 Years Ended December 31,
 2017 2016 2015
Revenues:     
Investment in ETP:     
Revenues from external customers$28,613
 $21,618
 $34,156
Intersegment revenues441
 209
 136
 29,054
 21,827
 34,292
Investment in Sunoco LP:     
Revenues from external customers11,713
 9,977
 12,419
Intersegment revenues10
 9
 11
 11,723
 9,986
 12,430
Investment in Lake Charles LNG:     
Revenues from external customers197
 197
 216
 

 

 

Adjustments and Eliminations:(451) (218) (10,842)
Total revenues$40,523
 $31,792
 $36,096
      
Costs of products sold:     
Investment in ETP$20,801
 $15,080
 $26,714
Investment in Sunoco LP10,615
 8,830
 11,450
Adjustments and Eliminations(450) (217) (9,496)
Total costs of products sold$30,966
 $23,693
 $28,668
      
Depreciation, depletion and amortization:     
Investment in ETP$2,332
 $1,986
 $1,929
Investment in Sunoco LP169
 176
 150
Investment in Lake Charles LNG39
 39
 39
Corporate and Other14
 15
 17
Adjustments and Eliminations—
 —
 (184)
Total depreciation, depletion and amortization$2,554
 $2,216
 $1,951
 Years Ended December 31,
 2017 2016 2015
Equity in earnings of unconsolidated affiliates:     
Investment in ETP$156
 $59
 $469
Adjustments and Eliminations(12) 211
 (193)
Total equity in earnings of unconsolidated affiliates$144
 $270
 $276

 Years Ended December 31,
 2017 2016 2015
Segment Adjusted EBITDA:     
Investment in ETP$6,712
 $5,733
 $5,517
Investment in Sunoco LP732
 665
 719
Investment in Lake Charles LNG175
 179
 196
Corporate and Other(31) (170) (104)
Adjustments and Eliminations(268) (272) (590)
Total Segment Adjusted EBITDA7,320
 6,135
 5,738
Depreciation, depletion and amortization(2,554) (2,216) (1,951)
Interest expense, net of interest capitalized(1,922) (1,804) (1,622)
Gains on acquisitions—
 83
 —
Impairment of investments in unconsolidated affiliates(313) (308) —
Impairment losses(1,039) (1,040) (339)
Losses on interest rate derivatives(37) (12) (18)
Non-cash unit-based compensation expense(99) (70) (91)
Unrealized gains (losses) on commodity risk management activities59
 (136) (65)
Losses on extinguishments of debt(89) —
 (43)
Inventory valuation adjustments24
 97
 (67)
Adjusted EBITDA related to discontinued operations(223) (199) (228)
Adjusted EBITDA related to unconsolidated affiliates(716) (675) (713)
Equity in earnings of unconsolidated affiliates144
 270
 276
Other, net155
 79
 23
Income from continuing operations before income tax benefit$710
 $204
 $900
Income tax benefit from continuing operations(1,833) (258) (123)
Income from continuing operations2,543
 462
 1,023
Income (loss) from discontinued operations, net of tax(177) (462) 38
Net income$2,366
 $—
 $1,061
 December 31,
 2017 2016 2015
Total assets:     
Investment in ETP$77,965
 $70,105
 $65,128
Investment in Sunoco LP8,344
 8,701
 8,842
Investment in Lake Charles LNG1,646
 1,508
 1,369
Corporate and Other598
 711
 638
Adjustments and Eliminations(2,307) (2,100) (4,833)
Total$86,246
 $78,925
 $71,144

 Years Ended December 31,
 2017 2016 2015
Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):     
Investment in ETP$5,901
 $5,810
 $8,167
Investment in Sunoco LP103
 119
 178
Investment in Lake Charles LNG2
 —
 1
Adjustments and Eliminations—
 —
 (123)
Total$6,006
 $5,929
 $8,223
 December 31,
 2017 2016 2015
Advances to and investments in affiliates:     
Investment in ETP$3,816
 $4,280
 $5,003
Adjustments and Eliminations(1,111) (1,240) (1,541)
Total$2,705
 $3,040
 $3,462
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP.
Investment in ETP
 Years Ended December 31,
 2017 2016 2015
Intrastate Transportation and Storage$2,891
 $2,155
 $1,912
Interstate Transportation and Storage915
 946
 1,008
Midstream2,510
 2,342
 2,607
NGL and refined products transportation and services8,326
 5,973
 4,569
Crude oil transportation and services11,672
 7,539
 8,980
All Other2,740
 2,872
 15,216
Total revenues29,054
 21,827
 34,292
Less: Intersegment revenues441
 209
 136
Revenues from external customers$28,613
 $21,618
 $34,156
Investment in Sunoco LP
 Years Ended December 31,
 2017 2016 2015
Retail operations$2,263
 $1,991
 $2,226
Wholesale operations9,460
 7,995
 10,204
Total revenues11,723
 9,986
 12,430
Less: Intersegment revenues10
 9
 11
Revenues from external customers$11,713
 $9,977
 $12,419
Investment in Lake Charles LNG
Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 2015, respectively, were related to LNG terminalling.

16.QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized unaudited quarterly financial data is presented below. Earnings per unit are exposedcomputed on a stand-alone basis for each quarter and total year.
 Quarters Ended  
 March 31* June 30* September 30* December 31 Total Year
2017:         
Revenues$9,660
 $9,427
 $9,984
 $11,452
 $40,523
Operating income (loss)758
 746
 924
 285
 2,713
Net income (loss)319
 121
 758
 1,168
 2,366
Limited Partners’ interest in net income232
 204
 240
 239
 915
Basic net income per limited partner unit$0.22
 $0.18
 $0.22
 $0.22
 $0.85
Diluted net income per limited partner unit$0.21
 $0.18
 $0.22
 $0.22
 $0.83
 Quarters Ended  
 March 31* June 30* September 30* December 31* Total Year*
2016:         
Revenues$6,447
 $7,866
 $8,156
 $9,323
 $31,792
Operating income680
 814
 624
 (275) 1,843
Net income (loss)320
 417
 (3) (734) —
Limited Partners’ interest in net income311
 239
 207
 226
 983
Basic net income per limited partner unit$0.30
 $0.23
 $0.20
 $0.22
 $0.94
Diluted net income per limited partner unit$0.30
 $0.23
 $0.19
 $0.21
 $0.92
* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to marketthe quarterly data has not been presented due to immateriality.
The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to ETP’s interstate transportation and storage operations, NGL and refined products operations and other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its interstate transportation and storage operations.

17.SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:
Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:
BALANCE SHEETS
 December 31,
 2017 2016
ASSETS   
CURRENT ASSETS:   
Cash and cash equivalents$1
 $2
Accounts receivable from related companies65
 55
Other current assets1
 —
Total current assets67
 57
PROPERTY, PLANT AND EQUIPMENT, net27
 36
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES6,082
 5,088
INTANGIBLE ASSETS, net—
 1
GOODWILL9
 9
OTHER NON-CURRENT ASSETS, net8
 10
Total assets$6,193
 $5,201
LIABILITIES AND PARTNERS’ CAPITAL   
CURRENT LIABILITIES:   
Accounts payable$—
 $1
Accounts payable to related companies—
 22
Interest payable66
 66
Accrued and other current liabilities4
 3
Total current liabilities70
 92
LONG-TERM DEBT, less current maturities6,700
 6,358
NOTE PAYABLE TO AFFILIATE617
 443
OTHER NON-CURRENT LIABILITIES2
 2
    
COMMITMENTS AND CONTINGENCIES
 
    
PARTNERS’ DEFICIT:   
General Partner(3) (3)
Limited Partners:   
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)(1,643) (1,871)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)450
 180
Total partners’ deficit(1,196) (1,694)
Total liabilities and partners’ deficit$6,193
 $5,201


STATEMENTS OF OPERATIONS
 Years Ended December 31,
 2017 2016 2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES$(31) $(185) $(112)
OTHER INCOME (EXPENSE):     
Interest expense, net of interest capitalized(347) (327) (294)
Equity in earnings of unconsolidated affiliates1,381
 1,511
 1,601
Loss on extinguishment of debt(47) —
 —
Other, net(2) (4) (5)
INCOME BEFORE INCOME TAXES954
 995
 1,190
Income tax expense—
 —
 1
NET INCOME954
 995
 1,189
General Partner’s interest in net income2
 3
 3
Convertible Unitholders’ interest in income37
 9
 —
Class D Unitholder’s interest in net income—
 —
 3
Limited Partners’ interest in net income$915
 $983
 $1,183


STATEMENTS OF CASH FLOWS
 Years Ended December 31,
 2017 2016 2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES$831
 $918
 $1,103
CASH FLOWS FROM INVESTING ACTIVITIES:     
Cash paid for Bakken Pipeline Transaction—
 —
 (817)
Contributions to unconsolidated affiliates(861) (70) —
Capital expenditures(1) (16) (19)
Contributions in aid of construction costs7
 —
 —
Net cash used in investing activities(855) (86) (836)
CASH FLOWS FROM FINANCING ACTIVITIES:     
Proceeds from borrowings2,219
 225
 3,672
Principal payments on debt(1,881) (210) (1,985)
Distributions to partners(1,010) (1,022) (1,090)
Proceeds from affiliate174
 176
 210
Common Units issued for cash568
 —
 —
Units repurchased under buyback program—
 —
 (1,064)
Debt issuance costs(47) —
 (11)
Net cash provided by (used in) financing activities23
 (831) (268)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(1) 1
 (1)
CASH AND CASH EQUIVALENTS, beginning of period2
 1
 2
CASH AND CASH EQUIVALENTS, end of period$1
 $2
 $1


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS
OF CERTAIN SUBSIDIARIES INCLUDED PURSUANT
TO RULE 3-16 OF REGULATION S-X
Page
1. Energy Transfer Partners, L.P. Financial StatementsS - 2


1.ENERGY TRANSFER PARTNERS, L.P. FINANCIAL STATEMENTS


INDEX TO FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting FirmS - 3
Consolidated Balance Sheets – December 31, 2017 and 2016S - 4
Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 and 2015S - 6
Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 and 2015S - 7
Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 and 2015S - 8
Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 and 2015S - 10
Notes to Consolidated Financial StatementsS - 12

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors of Energy Transfer Partners, L.L.C. and
Unitholders of Energy Transfer Partners, L.P.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 2018 (not separately included herein) expressed an unqualified opinion thereon.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2004.

Dallas, Texas
February 23, 2018


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
ASSETS   
Current assets:   
Cash and cash equivalents$306
 $360
Accounts receivable, net3,946
 3,002
Accounts receivable from related companies318
 209
Inventories1,589
 1,626
Income taxes receivable135
 128
Derivative assets24
 20
Other current assets210
 298
Total current assets6,528
 5,643
    
Property, plant and equipment67,699
 58,220
Accumulated depreciation and depletion(9,262) (7,303)
 58,437
 50,917
    
Advances to and investments in unconsolidated affiliates3,816
 4,280
Other non-current assets, net758
 672
Intangible assets, net5,311
 4,696
Goodwill3,115
 3,897
Total assets$77,965
 $70,105
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable$4,126
 $2,900
Accounts payable to related companies209
 43
Derivative liabilities109
 166
Accrued and other current liabilities2,143
 1,905
Current maturities of long-term debt407
 1,189
Total current liabilities6,994
 6,203
    
Long-term debt, less current maturities32,687
 31,741
Long-term notes payable – related company—
 250
Non-current derivative liabilities145
 76
Deferred income taxes2,883
 4,394
Other non-current liabilities1,084
 952
    
Commitments and contingencies
 

Legacy ETP Preferred Units—
 33
Redeemable noncontrolling interests21
 15
    
Equity:   
Series A Preferred Units (950,000 units authorized, issued and outstanding as of December 31, 2017)944
 —
Series B Preferred Units (550,000 units authorized, issued and outstanding as of December 31, 2017)547
 —
Limited Partners:   
Common Unitholders (1,164,112,575 and 794,803,854 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)26,531
 14,925
Class E Unitholder (8,853,832 units authorized, issued and outstanding – held by subsidiary)—
 —
Class G Unitholder (90,706,000 units authorized, issued and outstanding – held by subsidiary)—
 —
Class H Unitholder (81,001,069 units authorized, issued and outstanding as of December 31, 2016)—
 3,480
Class I Unitholder (100 units authorized, issued and outstanding)—
 2
Class K Unitholders (101,525,429 units authorized, issued and outstanding – held by subsidiaries)—
 —
General Partner244
 206
Accumulated other comprehensive income3
 8
Total partners’ capital28,269
 18,621
Noncontrolling interest5,882
 7,820
Total equity34,151
 26,441
Total liabilities and equity$77,965
 $70,105
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
 Years Ended December 31,
 2017 2016* 2015*
REVENUES:     
Natural gas sales$4,172
 $3,619
 $3,671
NGL sales6,972
 4,841
 3,936
Crude sales10,184
 6,766
 8,378
Gathering, transportation and other fees4,265
 4,003
 3,997
Refined product sales (see Note 3)1,515
 1,047
 9,958
Other (see Note 3)1,946
 1,551
 4,352
Total revenues29,054
 21,827
 34,292
COSTS AND EXPENSES:     
Cost of products sold (see Note 3)20,801
 15,080
 26,714
Operating expenses (see Note 3)2,170
 1,839
 2,608
Depreciation, depletion and amortization2,332
 1,986
 1,929
Selling, general and administrative (see Note 3)434
 348
 475
Impairment losses920
 813
 339
Total costs and expenses26,657
 20,066
 32,065
OPERATING INCOME2,397
 1,761
 2,227
OTHER INCOME (EXPENSE):     
Interest expense, net(1,365) (1,317) (1,291)
Equity in earnings from unconsolidated affiliates156
 59
 469
Impairment of investments in unconsolidated affiliates(313) (308) —
Gains on acquisitions—
 83
 —
Losses on extinguishments of debt(42) —
 (43)
Losses on interest rate derivatives(37) (12) (18)
Other, net209
 131
 22
INCOME BEFORE INCOME TAX BENEFIT1,005
 397
 1,366
Income tax benefit(1,496) (186) (123)
NET INCOME2,501
 583
 1,489
Less: Net income attributable to noncontrolling interest420
 295
 134
Less: Net loss attributable to predecessor—
 —
 (34)
NET INCOME ATTRIBUTABLE TO PARTNERS2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)$986
 $(1,019) $(27)
NET INCOME (LOSS) PER COMMON UNIT:     
Basic$0.94
 $(1.38) $(0.07)
Diluted$0.93
 $(1.38) $(0.08)
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
Net income$2,501
 $583
 $1,489
Other comprehensive income (loss), net of tax:     
Change in value of available-for-sale securities6
 2
 (3)
Actuarial gain (loss) relating to pension and other postretirement benefits(12) (1) 65
Foreign currency translation adjustment—
 (1) (1)
Change in other comprehensive income (loss) from unconsolidated affiliates1
 4
 (1)
 (5) 4
 60
Comprehensive income2,496
 587
 1,549
Less: Comprehensive income attributable to noncontrolling interest420
 295
 134
Less: Comprehensive loss attributable to predecessor—
 —
 (34)
Comprehensive income attributable to partners$2,076
 $292
 $1,449
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
     Limited Partners          
 Series A Preferred Units Series B Preferred Units Common Unit holders Class H Units Class I Units General
Partner		 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-controlling
Interest
 Predecessor Equity Total
Balance, December 31, 2014*$—
 $—
 $10,427
 $1,512
 $—
 $184
 $(56) $5,143
 $8,088
 $25,298
Distributions to partners—
 —
 (1,863) (247) (80) (944) —
 —
 —
 (3,134)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (338) —
 (338)
Units issued for cash—
 —
 1,428
 —
 —
 —
 —
 —
 —
 1,428
Subsidiary units issued for cash—
 —
 298
 —
 —
 2
 —
 1,219
 —
 1,519
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 875
 —
 875
Bakken Pipeline Transaction—
 —
 (999) 1,946
 —
 —
 —
 72
 —
 1,019
Sunoco LP Exchange Transaction—
 —
 (52) —
 —
 —
 —
 (940) —
 (992)
Susser Exchange Transaction—
 —
 (68) —
 —
 —
 —
 —
 —
 (68)
Acquisition and disposition of noncontrolling interest—
 —
 (26) —
 —
 —
 —
 (39) —
 (65)
Predecessor distributions to partners—
 —
 —
 —
 —
 —
 —
 —
 (202) (202)
Predecessor units issued for cash—
 —
 —
 —
 —
 —
 —
 —
 34
 34
Regency Merger—
 —
 7,890
 —
 —
 —
 —
 —
 (7,890) —
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 60
 —
 —
 60
Other, net—
 —
 23
 —
 —
 —
 —
 36
 4
 63
Net income (loss)—
 —
 (27) 258
 94
 1,064
 —
 134
 (34) 1,489
Balance, December 31, 2015*—
 —
 17,031
 3,469
 14
 306
 4
 6,162
 —
 26,986
Distributions to partners—
 —
 (2,134) (340) (20) (1,048) —
 —
 —
 (3,542)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (481) —
 (481)
Units issued for cash—
 —
 1,098
 —
 —
 —
 —
 —
 —
 1,098
Subsidiary units issued—
 —
 37
 —
 —
 —
 —
 1,351
 —
 1,388

Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 236
 —
 236
Sunoco, Inc. retail business to Sunoco LP transaction—
 —
 (405) —
 —
 —
 —
 —
 —
 (405)
PennTex Acquisition—
 —
 307
 —
 —
 —
 —
 236
 —
 543
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 4
 —
 —
 4
Other, net—
 —
 10
 —
 —
 —
 —
 21
 —
 31
Net income (loss)—
 —
 (1,019) 351
 8
 948
 —
 295
 —
 583
Balance, December 31, 2016*—
 —
 14,925
 3,480
 2
 206
 8
 7,820
 —
 26,441
Distributions to partners—
 —
 (2,419) (95) (2) (952) —
 —
 —
 (3,468)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (430) —
 (430)
Units issued for cash937
 542
 2,283
 —
 —
 —
 —
 —
 —
 3,762
Sunoco Logistics Merger—
 —
 9,416
 (3,478) —
 —
 —
 (5,938) —
 —
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 2,202
 —
 2,202
Sale of Bakken Pipeline interest—
 —
 1,260
 —
 —
 —
 —
 740
 —
 2,000
Sale of Rover Pipeline interest—
 —
 93
 —
 —
 —
 —
 1,385
 —
 1,478
Acquisition of PennTex noncontrolling interest—
 —
 (48) —
 —
 —
 —
 (232) —
 (280)
Other comprehensive loss, net of tax—
 —
 —
 —
 —
 —
 (5) —
 —
 (5)
Other, net—
 —
 35
 —
 —
 —
 —
 (85) —
 (50)
Net income7
 5
 986
 93
 —
 990
 —
 420
 —
 2,501
Balance, December 31, 2017$944
 $547
 $26,531
 $—
 $—
 $244
 $3
 $5,882
 $—
 $34,151
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
OPERATING ACTIVITIES:     
Net income$2,501
 $583
 $1,489
Reconciliation of net income to net cash provided by operating activities:     
Depreciation, depletion and amortization2,332
 1,986
 1,929
Deferred income taxes(1,531) (169) 202
Amortization included in interest expense2
 (20) (36)
Inventory valuation adjustments—
 —
 (58)
Unit-based compensation expense74
 80
 79
Impairment losses920
 813
 339
Gains on acquisitions—
 (83) —
Losses on extinguishments of debt42
 —
 43
Impairment of investments in unconsolidated affiliates313
 308
 —
Distributions on unvested awards(31) (25) (16)
Equity in earnings of unconsolidated affiliates(156) (59) (469)
Distributions from unconsolidated affiliates440
 406
 440
Other non-cash(261) (271) (22)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations(160) (246) (1,173)
Net cash provided by operating activities4,485
 3,303
 2,747
INVESTING ACTIVITIES:     
Cash proceeds from sale of Bakken Pipeline interest2,000
 —
 —
Cash proceeds from sale of Rover Pipeline interest1,478
 —
 —
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction—
 2,200
 —
Proceeds from Bakken Pipeline Transaction—
 —
 980
Proceeds from Susser Exchange Transaction—
 —
 967
Proceeds from sale of noncontrolling interest—
 —
 64
Cash paid for acquisition of PennTex noncontrolling interest(280) —
 —
Cash paid for Vitol Acquisition, net of cash received—
 (769) —
Cash paid for PennTex Acquisition, net of cash received—
 (299) —
Cash transferred to ETE in connection with the Sunoco LP Exchange—
 —
 (114)
Cash paid for acquisition of a noncontrolling interest—
 —
 (129)
Cash paid for all other acquisitions(264) (159) (675)
Capital expenditures, excluding allowance for equity funds used during construction(8,335) (7,550) (9,098)
Contributions in aid of construction costs24
 71
 80
Contributions to unconsolidated affiliates(268) (59) (45)
Distributions from unconsolidated affiliates in excess of cumulative earnings136
 135
 124
Proceeds from the sale of assets35
 25
 23
Change in restricted cash—
 14
 19
Other1
 1
 (16)
Net cash used in investing activities(5,473) (6,390) (7,820)
      

FINANCING ACTIVITIES:     
Proceeds from borrowings26,736
 19,916
 22,462
Repayments of long-term debt(26,494) (15,799) (17,843)
Cash (paid to) received from affiliate notes(255) 124
 233
Common Units issued for cash2,283
 1,098
 1,428
Preferred Units issued for cash1,479
 —
 —
Subsidiary units issued for cash—
 1,388
 1,519
Predecessor units issued for cash—
 —
 34
Capital contributions from noncontrolling interest1,214
 236
 841
Distributions to partners(3,468) (3,542) (3,134)
Predecessor distributions to partners—
 —
 (202)
Distributions to noncontrolling interest(430) (481) (338)
Redemption of Legacy ETP Preferred Units(53) —
 —
Debt issuance costs(83) (22) (63)
Other5
 2
 —
Net cash provided by financing activities934
 2,920
 4,937
Decrease in cash and cash equivalents(54) (167) (136)
Cash and cash equivalents, beginning of period360
 527
 663
Cash and cash equivalents, end of period$306
 $360
 $527
* As adjusted. See Note 2.




ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)

1.OPERATIONS AND BASIS OF PRESENTATION:
Organization. The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETP”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner.
In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled.
In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein:
References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;
References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and
References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.
The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes).
The Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales.
The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.
The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.

The Partnership owns a controlling interest in Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the date the financial statements were issued.
For prior periods reported herein, certain transactions related to the volatilitybusiness of commodity prices. To managelegacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.
The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, these undivided interests are consolidated proportionately.
2.ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Change in Accounting Policy
During the impactfourth quarter of volatility from these prices, we utilize various exchange-traded2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and OTC commodityNGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows:
 Year Ended December 31, 2016 Year Ended December 31, 2015
 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted
Consolidated Statement of Operations and Comprehensive Income:           
Cost of products sold$15,039
 $41
 $15,080
 $26,682
 $32
 $26,714
Operating income1,802
 (41) 1,761
 2,259
 (32) 2,227
Income before income tax benefit438
 (41) 397
 1,398
 (32) 1,366
Net income624
 (41) 583
 1,521
 (32) 1,489
Net income attributable to partners297
 (9) 288
 1,398
 (9) 1,389
Net loss per common unit - basic(1.37) (0.01) (1.38) (0.06) (0.01) (0.07)
Net loss per common unit - diluted(1.37) (0.01) (1.38) (0.07) (0.01) (0.08)
Comprehensive income628
 (41) 587
 1,581
 (32) 1,549
Comprehensive income attributable to partners301
 (9) 292
 1,458
 (9) 1,449
            
Consolidated Statements of Cash Flows:           
Net income624
 (41) 583
 1,521
 (32) 1,489
Net change in operating assets and liabilities (change in inventories)(117) (129) (246) (1,367) 194
 (1,173)
            
Consolidated Balance Sheets (at period end):           
Inventories1,712
 (86) 1,626
 1,213
 (45) 1,168
Total partners' capital18,642
 (21) 18,621
 20,836
 (12) 20,824
* Amounts reflect certain reclassifications made to conform to the current year presentation.
Use of Estimates
The preparation of financial instrument contracts. These contracts consist primarilystatements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of futures, swapsassets and optionsliabilities and are recordedthe accrual for and disclosure of contingent assets and liabilities at fair value in our consolidated balance sheets.the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
We inject and holdThe natural gas in our Bammelindustry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage facility to take advantage of contango markets (i.e., when the price of natural gas is higheroperations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the future thanfollowing month’s financial statements. Management believes that the current spot price). We use financial derivatives to hedgeestimated operating results represent the natural gas heldactual results in connection with these arbitrage opportunities. At the inceptionall material respects.
Some of the hedge, we lock in a marginother significant estimates made by purchasing gas inmanagement include, but are not limited to, the spot market or off peak season and entering into a financial contract to lock in the sale price. If we designate the related financial contract as a fair value hedge for accounting purposes, we value thetiming of certain forecasted transactions that are hedged, natural gas inventory at current spot

S - 57

market prices along with the financial derivative we use to hedge it. Changes in the spread between the forward natural gas prices designated as fair value hedges and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. Unrealized margins represent the unrealized gains or losses from our derivative instruments using mark-to-market accounting, with changes in the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Recent Accounting Pronouncements
ASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.
For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of our derivatives being recorded directly in earnings. These margins fluctuate based uponmidstream segment agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the spreads betweenaccounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.
ASU 2016-02
In February 2016, the physical spot priceFASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and forwardlessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-16
On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.
ASU 2017-12
In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
Revenue Recognition
Revenues for sales of natural gas prices. Ifand NGLs are recognized at the spread narrows betweenlater of the physical and financial prices, we will record unrealized gains or lower unrealized losses. Iftime of delivery of the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enterproduct to the winter months, the spread converges so that we recognize in earnings the original locked-in spread through either mark-to-market adjustmentscustomer or the physical withdrawtime of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas.
Wegas that flows through the transportation pipelines. Under transportation contracts, our customers are also exposedcharged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to market risk onpay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the

pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we retain for fees inpurchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.
In addition, our intrastate transportation and storage segment generates revenues and operationalmargin from fees charged for storing customers’ working natural gas sales onin our interstate transportationstorage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage segment.reservoir. We usepurchase physical natural gas and then sell financial derivativescontracts at a price sufficient to hedgecover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the sales priceperiods from November to March of thiseach year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including futures, swaps and options. Certain contracts that qualify for hedge accounting are designated as cash flow hedges of the forecasted saleweather, availability of natural gas.gas in regions in which we operate, competitive factors in the energy industry, and other issues.
Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and segment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The change in value,revenue earned from these arrangements is directly related to the extent the contracts are effective, remains in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gain or loss associated with the derivativevolume of natural gas that flows through our systems and is recorded in cost of products sold in the consolidated statement of operations.not directly dependent on commodity prices.
We are also exposed to commodity price risk on NGLs and residue gas we retain for feesutilize other types of arrangements in our midstream segment, whereby our subsidiaries generallyincluding (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.
In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

Regulatory Accounting – Regulatory Assets and Liabilities
Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the residueperiod in which the discontinuance of regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and NGLs.storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We useconsider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:
 Years Ended December 31,
 2017 2016 2015
Accounts receivable$(950) $(919) $819
Accounts receivable from related companies67
 30
 (243)
Inventories37
 (497) (157)
Other current assets39
 83
 (178)
Other non-current assets, net(94) (78) 188
Accounts payable758
 972
 (1,215)
Accounts payable to related companies(3) 29
 (160)
Accrued and other current liabilities(47) 39
 (83)
Other non-current liabilities24
 33
 (219)
Price risk management assets and liabilities, net9
 62
 75
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations$(160) $(246) $(1,173)

Non-cash investing and financing activities and supplemental cash flow information are as follows:
 Years Ended December 31,
 2017 2016 2015
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$1,059
 $822
 $896
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP—
 194
 —
Net gains from subsidiary common unit transactions—
 37
 300
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with the PennTex Acquisition$—
 $307
 $—
Issuance of Common Units in connection with the Regency Merger—
 —
 9,250
Issuance of Class H Units in connection with the Bakken Pipeline Transaction—
 —
 1,946
Contribution of assets from noncontrolling interest988
 —
 34
Redemption of Common Units in connection with the Bakken Pipeline Transaction—
 —
 999
Redemption of Common Units in connection with the Sunoco LP Exchange—
 —
 52
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$1,329
 $1,411
 $1,467
Cash paid for (refund of) income taxes50
 (229) 71
Accounts Receivable
Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.
We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.
We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories
As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017.
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Inventories consisted of the following:
 December 31,
 2017 2016
Natural gas, NGLs, and refined products$733
 $758
Crude oil551
 651
Spare parts and other305
 217
Total inventories$1,589
 $1,626
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Other Current Assets
Other current assets consisted of the following:
 December 31,
 2017 2016
Deposits paid to vendors$64
 $74
Prepaid expenses and other146
 224
Total other current assets$210
 $298
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the NGL and crude derivative swap contractsrefined products transportation and services segment primarily due to hedge forecasted salesan expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:
 December 31,
 2017 2016
Land and improvements$1,706
 $676
Buildings and improvements (1 to 45 years)1,960
 1,617
Pipelines and equipment (5 to 83 years)44,050
 36,356
Natural gas and NGL storage facilities (5 to 46 years)1,681
 1,452
Bulk storage, equipment and facilities (2 to 83 years)3,036
 3,701
Vehicles (1 to 25 years)124
 217
Right of way (20 to 83 years)3,424
 3,349
Natural resources434
 434
Other (1 to 40 years)534
 484
Construction work-in-process10,750
 9,934
 67,699
 58,220
Less – Accumulated depreciation and depletion(9,262) (7,303)
Property, plant and equipment, net$58,437
 $50,917
We recognized the following amounts for the periods presented:
 Years Ended December 31,
 2017 2016 2015
Depreciation and depletion expense$2,060
 $1,793
 $1,713
Capitalized interest283
 199
 163
Advances to and Investments in Unconsolidated Affiliates
We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
 December 31,
 2017 2016
Regulatory assets$85
 $86
Deferred charges210
 217
Restricted funds192
 190
Long-term affiliated receivable85
 90
Other186
 89
Total other non-current assets, net$758
 $672
(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.
Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.

Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:
 December 31, 2017 December 31, 2016
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:       
Customer relationships, contracts and agreements (3 to 46 years)$6,250
 $(1,003) $5,362
 $(737)
Patents (10 years)48
 (26) 48
 (21)
Trade Names (20 years)66
 (25) 66
 (22)
Other (5 to 20 years)1
 —
 2
 (2)
Total intangible assets$6,365
 $(1,054) $5,478
 $(782)
Aggregate amortization expense of intangible assets was as follows:
 Years Ended December 31,
 2017 2016 2015
Reported in depreciation, depletion and amortization$272
 $193
 $216
Estimated aggregate amortization expense for the next five years is as follows:
Years Ending December 31: 
2018$280
2019278
2020278
2021268
2022256
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
In 2015, we recorded $24 million of intangible asset impairments related to the NGL and condensate equity volumes. Certain contractsrefined products transportation and services segment primarily due to an expected decrease in future cash flows.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:
 Intrastate
Transportation
and Storage		 Interstate
Transportation and Storage		 Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services All Other Total
Balance, December 31, 2015$10
 $912
 $718
 $772
 $912
 $2,104
 $5,428
Reduction due to contribution of legacy Sunoco, Inc. retail business—
 —
 —
 —
 —
 (1,289) (1,289)
Acquired—
 —
 177
 —
 251
 —
 428
Impaired—
 (638) (32) —
 —
 —
 (670)
Balance, December 31, 201610
 274
 863
 772
 1,163
 815
 3,897
Acquired—
 —
 8
 —
 4
 —
 12
Impaired—
 (262) —
 (79) —
 (452) (793)
Other—
 —
 (1) —
 —
 —
 (1)
Balance, December 31, 2017$10
 $12
 $870
 $693
 $1,167
 $363
 $3,115
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve.
During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.
The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted

risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Long-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
 December 31,
 2017 2016
Interest payable$443
 $440
Customer advances and deposits59
 56
Accrued capital expenditures1,006
 749
Accrued wages and benefits208
 212
Taxes payable other than income taxes108
 63
Exchanges payable154
 208
Other165
 177
Total accrued and other current liabilities$2,143
 $1,905
Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for hedgeopen credit.

Redeemable Noncontrolling Interests
The noncontrolling interest holders in one of our consolidated subsidiaries has the option to sell its interests to us.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheet.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $32.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as cash flow hedges. The changeassets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the extentlevel of activity of these contracts on the contractsexchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are effective, remainsunobservable. During the year ended December 31, 2017, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016 based on inputs used to derive their fair values:
 Fair Value Total Fair Value Measurements at December 31, 2017
 Level 1 Level 2
Assets:     
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX$11
 $11
 $—
Swing Swaps IFERC13
 —
 13
Fixed Swaps/Futures70
 70
 —
Forward Physical Swaps8
 —
 8
Power:     
Forwards23
 —
 23
Natural Gas Liquids – Forwards/Swaps193
 193
 —
Crude – Futures2
 2
 —
Total commodity derivatives320
 276
 44
Other non-current assets21
 14
 7
Total assets$341
 $290
 $51
Liabilities:     
Interest rate derivatives$(219) $—
 $(219)
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX(24) (24) —
Swing Swaps IFERC(15) (1) (14)
Fixed Swaps/Futures(57) (57) —
Forward Physical Swaps(2) —
 (2)
Power – Forwards(22) —
 (22)
Natural Gas Liquids – Forwards/Swaps(192) (192) —
Refined Products – Futures(25) (25) —
Crude – Futures(1) (1) —
Total commodity derivatives(338) (300) (38)
Total liabilities$(557) $(300) $(257)

 Fair Value Total Fair Value Measurements at December 31, 2016
 Level 1 Level 2 Level 3
Assets:       
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX$14
 $14
 $—
 $—
Swing Swaps IFERC2
 —
 2
 —
Fixed Swaps/Futures96
 96
 —
 —
Forward Physical Swaps1
 —
 1
 —
Power:       
Forwards4
 —
 4
 —
Futures1
 1
 —
 —
Options – Calls1
 1
 —
 —
Natural Gas Liquids – Forwards/Swaps233
 233
 —
 —
Refined Products – Futures1
 1
 —
 —
Crude – Futures9
 9
 —
 —
Total commodity derivatives362
 355
 7
 —
Other non-current assets13
 8
 5
 —
Total assets$375
 $363
 $12
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in the Legacy ETP Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) —
 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids – Forwards/Swaps(273) (273) —
 —
Refined Products – Futures(17) (17) —
 —
Crude – Futures(13) (13) —
 —
Total commodity derivatives(472) (464) (8) —
Total liabilities$(666) $(464) $(201) $(1)
Contributions in AOCI until the forecasted transaction occurs. When the forecasted transaction occurs, any gainAid of Construction Costs
On certain of our capital projects, third parties are obligated to reimburse us for all or lossa portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the derivativeperiod in which it is recordedrealized.
Shipping and Handling Costs
Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

Costs and Expenses
Cost of products sold include actual cost of fuel sold, adjusted for the consolidated statementeffects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We may use derivativesrecord the collection of taxes to be remitted to government authorities on a net basis except for our all other segment in our liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGLs.
Sunoco Logistics utilizes derivatives such as swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the pricewhich consumer excise taxes on sales of refined products and NGLs. These derivative contracts act as a hedging mechanism against the volatility of prices by allowing Sunoco Logistics to transfer this price risk to counterparties whomerchandise are ableincluded in both revenues and willing to bear it. Since the first quarter 2013, Sunoco Logistics has not designated any of its derivative contracts as hedges for accounting purposes. Therefore, all realizedcosts and unrealized gains and losses from these derivative contracts are recognizedexpenses in the consolidated statements of operations, duringwith no effect on net income (loss). For the current period.year ended December 31, 2015, excise taxes collected by Sunoco LP were $1.85 billion. The Partnership deconsolidated Sunoco LP effective July 1, 2015 and no excise taxes were collected by our consolidated operations subsequent to that date.
Issuances of Subsidiary Units
We also use derivatives to hedge a variety of price risksrecord changes in our retail marketing segment. Futuresownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and swapsthe amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Taxes
ETP is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, and 2015, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company and until July 31, 2015, Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floatingvalue our financial derivatives and related transactions have been determined using independent third-party prices, to lock in margins for certain refined productsreadily available market information, broker quotes and to lock in the priceappropriate valuation techniques.

At inception of a portionhedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of natural gas purchases or salesthe hedge and transportation costs. Theon a quarterly basis, whether the derivatives that are used in our retail marketing segment represent economic hedges; however,hedging transactions are highly effective in offsetting changes in cash flows. If we have elected not to designate anydetermine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the hedgesderivative in this business segment. Therefore, all realized and unrealized gains and losses from these derivative contracts are recognizednet income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the consolidated statements of operations during the current period.
Our trading activities include the use of financial commodity derivatives to take advantage of market opportunities. These trading activities are a complement to our transportation and storage segment’s operations and are nettedhedged asset or liability in cost of products sold in our consolidated statements of operations. Additionally,This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we also have tradingdesignate a derivative financial instrument as a cash flow hedge and marketing activitiesit qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to power and natural gascash flow hedges remain in our all other segment which are also nettedAOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold.sold in the consolidated statements of operations.
We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Unit-Based Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income
For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for United States Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.


3.ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
2018 Transactions
CDM Contribution Agreement
In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.
In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million.
2017 Transactions
Rover Contribution Agreement
In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatilityRover construction costs incurred by ETP through the useclosing date, along with the payment of daily positionadditional amounts subject to certain adjustments.
ETP and profitSunoco Logistics Merger
As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and loss reports providedSunoco Logistics completed the Sunoco Logistics Merger.
Permian Express Partners
In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to our risk oversight committee,Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which includes membersresulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of senior management,all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
2016 Transactions
PennTex Acquisition
On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, the limitsPartnership purchased PennTex’s remaining outstanding common units in June 2017.
Summary of Assets Acquired and authorizations set forth in our commodity risk management policy.Liabilities Assumed

S - 58
TableWe accounted for the PennTex acquisition using the acquisition method of Contentsaccounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.

The following table details our outstanding commodity-related derivatives:total purchase price was allocated as follows:
 December 31, 2014 December 31, 2013
 
Notional
Volume
 Maturity 
Notional
Volume
 Maturity
Mark-to-Market Derivatives       
(Trading)       
Natural Gas (MMBtu):       
Fixed Swaps/Futures(232,500) 2015 9,457,500
 2014-2019
Basis Swaps IFERC/NYMEX(1)
(13,907,500) 2015-2016 (487,500) 2014-2017
Swing Swaps—
 — 1,937,500
 2014-2016
Options – Calls5,000,000
 2015 —
 —
Power (Megawatt):       
Forwards288,775
 2015 351,050
 2014
Futures(156,000) 2015 (772,476) 2014
Options – Puts(72,000) 2015 (52,800) 2014
Options – Calls198,556
 2015 103,200
 2014
Crude (Bbls) – Futures—
 — 103,000
 2014
(Non-Trading)       
Natural Gas (MMBtu):       
Basis Swaps IFERC/NYMEX57,500
 2015 570,000
 2014
Swing Swaps IFERC46,150,000
 2015 (9,690,000) 2014-2016
Fixed Swaps/Futures(8,779,000) 2015-2016 (8,195,000) 2014-2015
Forward Physical Contracts(9,116,777) 2015 5,668,559
 2014-2015
Natural Gas Liquid (Bbls) – Forwards/Swaps(2,179,400) 2015 (1,133,600) 2014
Refined Products (Bbls) – Futures13,745,755
 2015 (280,000) 2014
Fair Value Hedging Derivatives       
(Non-Trading)       
Natural Gas (MMBtu):       
Basis Swaps IFERC/NYMEX(39,287,500) 2015 (7,352,500) 2014
Fixed Swaps/Futures(39,287,500) 2015 (50,530,000) 2014
Hedged Item – Inventory39,287,500
 2015 50,530,000
 2014
Cash Flow Hedging Derivatives       
(Non-Trading)       
Natural Gas (MMBtu):       
Basis Swaps IFERC/NYMEX—
 — (1,825,000) 2014
Fixed Swaps/Futures—
 — (12,775,000) 2014
Natural Gas Liquid (Bbls) – Forwards/Swaps—
 — (780,000) 2014
Crude (Bbls) – Futures—
 — (30,000) 2014
  At November 1, 2016
Total current assets $34
Property, plant and equipment 393
Goodwill(1)
 177
Intangible assets 446
  1,050
   
Total current liabilities 6
Long-term debt, less current maturities 164
Other non-current liabilities 17
Noncontrolling interest 236
  423
Total consideration 627
Cash received 21
Total consideration, net of cash received $606
(1) 
Includes aggregate amountsNone of the goodwill is expected to be deductible for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.tax purposes.
Interest Rate RiskThe fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
We are exposed to market riskSunoco Logistics’ Vitol Acquisition
In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for changes$760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in interest rates. To maintainMidland, Texas, a cost effective capital structure, we borrow funds using a mix of fixed rate debtcrude oil gathering and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lockmainline pipeline system in the rateMidland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to 100%. The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million.

Bakken Financing
In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billion credit facility provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $2.50 billion was outstanding under this credit facility.
Bayou Bridge
In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system.
Sunoco Retail to Sunoco LP
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of $1.29 billion and intangible assets of $294 million. The results of Sunoco, LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.
Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated:
 Year Ended December 31, 2015
Revenues$12,482
Cost of products sold11,174
Operating expenses798
Selling, general and administrative expenses106
2015 Transactions
Sunoco LP
In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015.
In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE provided ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. In connection with this transaction, the Partnership deconsolidated Sunoco LP, including goodwill of $1.81 billion and intangible assets of $982 million related to Sunoco LP. At December 31, 2017, the Partnership held 37.8 million Sunoco LP common units accounted for under the equity method. Subsequent to Sunoco LP’s

repurchase of a portion of its common units on February 7, 2018, as discussed in Note 4, our anticipated debt issuances.investment in Sunoco LP consists of 26.2 million units. The results of Sunoco LP’s operations have not been presented as discontinued operations and Sunoco LP’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.
Bakken Pipeline
In March 2015, ETE transferred 46.2 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017.
In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.
Regency Merger
On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 Partnership common units. ETP issued 258.3 million Partnership common units to Regency unitholders, including 23.3 million units issued to Partnership subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding Legacy ETP Preferred Units on a one-for-one basis.
In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.
The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger.
ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.

4.ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
Citrus
ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, an approximately 5,360-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment.
FEP
We have a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. The Partnership recorded an impairment of its investment

in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor.
MEP
We own a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016.
HPC
We own a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Our investment in HPC is reflected in the intrastate transportation and storage segment. The Partnership evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, the Partnership recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.
Sunoco LP
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from the Partnership. As a result, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. As of December 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units, and is reflected in the all other segment.
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.
The carrying values of the Partnership’s advances to and investments in unconsolidated affiliates as of December 31, 2017 and 2016 were as follows:
S - 59
 December 31,
 2017 2016
Citrus$1,754
 $1,729
FEP121
 101
MEP242
 318
HPC28
 382
Sunoco LP1,095
 1,225
Others576
 525
Total$3,816
 $4,280

The following table summarizes our interest rate swaps outstanding, nonepresents equity in earnings (losses) of which were designated as hedges for accounting purposes:unconsolidated affiliates:
Entity Term 
Type(1)
 Notional Amount Outstanding
December 31, 2014 December 31, 2013
ETP 
July 2014(2)
 Forward-starting to pay a fixed rate of 4.25% and receive a floating rate $—
 $400
ETP 
July 2015(2)
 Forward-starting to pay a fixed rate of 3.38% and receive a floating rate 200
 —
ETP 
July 2016(3)
 Forward-starting to pay a fixed rate of 3.80% and receive a floating rate 200
 —
ETP 
July 2017(4)
 Forward-starting to pay a fixed rate of 3.84% and receive a floating rate 300
 —
ETP 
July 2018(4)
 Forward-starting to pay a fixed rate of 4.00% and receive a floating rate 200
 —
ETP 
July 2019(4)
 Forward-starting to pay a fixed rate of 3.19% and receive a floating rate 300
 —
ETP July 2018 Pay a floating rate plus a spread of 4.17% and receive a fixed rate of 6.70% —
 600
ETP June 2021 Pay a floating rate plus a spread of 2.17% and receive a fixed rate of 4.65% —
 400
ETP February 2023 Pay a floating rate plus a spread of 1.73% and receive a fixed rate of 3.60% 200
 400
Panhandle November 2021 Pay a fixed rate of 3.82% and receive a floating rate —
 275
 Years Ended December 31,
 2017 2016 2015
Citrus$144
 $102
 $97
FEP53
 51
 55
MEP38
 40
 45
HPC(1)
(168) 31
 32
Sunoco, LLC—
 —
 (10)
Sunoco LP(2)
12
 (211) 202
Other77
 46
 48
Total equity in earnings of unconsolidated affiliates156
 59
 469
(1) 
Floating ratesFor the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
(2)
For the years ended December 31, 2017 and 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million, respectively.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, HPC and Sunoco LP (on a 100% basis) for all periods presented:
 December 31,
 2017 2016
Current assets$4,750
 $1,532
Property, plant and equipment, net9,893
 10,310
Other assets2,286
 5,980
Total assets$16,929
 $17,822
    
Current liabilities$2,075
 $1,918
Non-current liabilities9,375
 10,343
Equity5,479
 5,561
Total liabilities and equity$16,929
 $17,822
 Years Ended December 31,
 2017 2016 2015
Revenue$13,081
 $11,150
 $13,815
Operating income636
 859
 1,052
Net income (loss)294
 (22) 664
In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.


5.NET INCOME (LOSS) PER LIMITED PARTNER UNIT:
The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
 Years Ended December 31,
 2017 2016 2015
Net income$2,501
 $583
 $1,489
Less: Income attributable to noncontrolling interest420
 295
 134
Less: Loss attributable to predecessor—
 —
 (34)
Net income, net of noncontrolling interest2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)986
 (1,019) (27)
Additional earnings allocated from (to) General Partner9
 (10) (5)
Distributions on employee unit awards, net of allocation to General Partner(27) (19) (16)
Net income (loss) available to Common Unitholders$968
 $(1,048) $(48)
Weighted average Common Units – basic1,032.7
 758.2
 649.2
Basic net income (loss) per Common Unit$0.94
 $(1.38) $(0.07)
      
Income (loss) available to Common Unitholders$968
 $(1,048) $(48)
Loss attributable to Legacy ETP Preferred Units—
 —
 (6)
Diluted income (loss) available to Common Unitholders$968
 $(1,048) $(54)
Weighted average Common Units – basic1,032.7
 758.2
 649.2
Dilutive effect of unvested Unit Awards5.1
 —
 —
Dilutive effect of Legacy ETP Preferred Units—
 —
 1.0
Weighted average Common Units – diluted1,037.8
 758.2
 650.2
Diluted income (loss) per Common Unit$0.93
 $(1.38) $(0.08)

6.DEBT OBLIGATIONS:
Our debt obligations consist of the following:
 December 31,
 2017 2016
ETP Debt   
6.125% Senior Notes due February 15, 2017$—
 $400
2.50% Senior Notes due June 15, 2018 (1)650
 650
6.70% Senior Notes due July 1, 2018 (1)600
 600
9.70% Senior Notes due March 15, 2019400
 400
9.00% Senior Notes due April 15, 2019450
 450
5.50% Senior Notes due February 15, 2020250
 250
5.75% Senior Notes due September 1, 2020400
 400

4.15% Senior Notes due October 1, 20201,050
 1,050
4.40% Senior Notes due April 1, 2021600
 600
6.50% Senior Notes due July 15, 2021—
 500
4.65% Senior Notes due June 1, 2021800
 800
5.20% Senior Notes due February 1, 20221,000
 1,000
4.65% Senior Notes due February 15, 2022300
 300
5.875% Senior Notes due March 1, 2022900
 900
5.00% Senior Notes due October 1, 2022700
 700
3.45% Senior Notes due January 15, 2023350
 350
3.60% Senior Notes due February 1, 2023800
 800
5.50% Senior Notes due April 15, 2023—
 700
4.50% Senior Notes due November 1, 2023600
 600
4.90% Senior Notes due February 1, 2024350
 350
7.60% Senior Notes due February 1, 2024277
 277
4.25% Senior Notes due April 1, 2024500
 500
9.00% Debentures due November 1, 202465
 65
4.05% Senior Notes due March 15, 20251,000
 1,000
5.95% Senior Notes due December 1, 2025400
 400
4.75% Senior Notes due January 15, 20261,000
 1,000
3.90% Senior Notes due July 15, 2026550
 550
4.20% Senior Notes due April 15, 2027600
 —
4.00% Senior Notes due October 1, 2027750
 —
8.25% Senior Notes due November 15, 2029267
 267
4.90% Senior Notes due March 15, 2035500
 500
6.625% Senior Notes due October 15, 2036400
 400
7.50% Senior Notes due July 1, 2038550
 550
6.85% Senior Notes due February 15, 2040250
 250
6.05% Senior Notes due June 1, 2041700
 700
6.50% Senior Notes due February 1, 20421,000
 1,000
6.10% Senior Notes due February 15, 2042300
 300
4.95% Senior Notes due January 15, 2043350
 350
5.15% Senior Notes due February 1, 2043450
 450
5.95% Senior Notes due October 1, 2043450
 450
5.30% Senior Notes due April 1, 2044700
 700
5.15% Senior Notes due March 15, 20451,000
 1,000
5.35% Senior Notes due May 15, 2045800
 800
6.125% Senior Notes due December 15, 20451,000
 1,000
5.30% Senior Notes due April 15, 2047900
 —
5.40% Senior Notes due October 1, 20471,500
 —
Floating Rate Junior Subordinated Notes due November 1, 2066546
 546
ETP $4.0 billion Revolving Credit Facility due December 20222,292
 —
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)50
 —
ETLP $3.75 billion Revolving Credit Facility due November 2019—
 2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020—
 1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017—
 630
Unamortized premiums, discounts and fair value adjustments, net33
 66
Deferred debt issuance costs(170) (166)
 29,210
 29,454
Transwestern Debt   
5.64% Senior Notes due May 24, 2017—
 82
5.36% Senior Notes due December 9, 2020175
 175
5.89% Senior Notes due May 24, 2022150
 150
5.66% Senior Notes due December 9, 2024175
 175
6.16% Senior Notes due May 24, 203775
 75
Deferred debt issuance costs(1) (1)
 574
 656
Panhandle Debt   
6.20% Senior Notes due November 1, 2017—
 300

7.00% Senior Notes due June 15, 2018400
 400
8.125% Senior Notes due June 1, 2019150
 150
7.60% Senior Notes due February 1, 202482
 82
7.00% Senior Notes due July 15, 202966
 66
8.25% Senior Notes due November 15, 202933
 33
Floating Rate Junior Subordinated Notes due November 1, 206654
 54
Unamortized premiums, discounts and fair value adjustments, net28
 50
 813
 1,135
Sunoco, Inc. Debt   
5.75% Senior Notes due January 15, 2017—
 400
    
Bakken Project Debt   
Bakken Project $2.50 billion Credit Facility due August 20192,500
 1,100
Deferred debt issuance costs(8) (13)
 2,492
 1,087
PennTex Debt   
PennTex $275 million Revolving Credit Facility due December 2019—
 168
    
Other5
 30
 33,094
 32,930
Less: Current maturities of long-term debt407
 1,189
 $32,687
 $31,741
(1)
As of December 31, 2017 management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.
(2)
Borrowings under 364-day credit facilities were classified as long-term debt based on 3-month LIBOR.the Partnership’s ability and intent to refinance such borrowings on a long-term basis.
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs:
2018 $1,700
2019 3,500
2020 1,875
2021 1,400
2022 5,346
Thereafter 19,391
Total $33,212
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
ETP Senior Notes
The ETP senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.
The ETP senior notes are unsecured obligations of the Partnership and as a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

Transwestern Senior Notes
The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017.
Credit Facilities and Commercial Paper
ETP Credit Facilities
On December 1, 2017 the Partnership entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).  The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to $6.0 billion under certain conditions. We use the ETP Credit Facilities to provide temporary financing for our growth projects, as well as for general partnership purposes.
As of December 31, 2017, the ETP Five-Year Facility had $2.29 billion outstanding, of which $2.01 billion was commercial paper. The amount available for future borrowings was $1.56 billion after taking into account letters of credit of $150 million. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 2.48%.
As of December 31, 2017, the ETP 364-Day Facility had $50 million outstanding, and the amount available for future borrowings was $950 million. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 5.00%.
ETLP Credit Facility
The ETLP Credit Facility allowed for borrowings of up to $3.75 billion and was used to provide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.
Sunoco Logistics Credit Facilities
ETP maintained a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.
In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2017, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%.
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

Covenants Related to Our Credit Agreements
Covenants Related to ETP
The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The ETP Credit Facilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
incur indebtedness;
grant liens;
enter into mergers;
dispose of assets;
make certain investments;
make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities);
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
engage in transactions with affiliates; and
enter into restrictive agreements.
The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from 0.125% to 0.300%.  The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225%.
The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as calculated in accordance with the credit agreements.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-

acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.
In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Bakken Credit Facility
The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:
prohibition of certain incremental secured indebtedness;
prohibition of certain liens / negative pledge;
limitations on uses of loan proceeds;
limitations on asset sales and purchases;
limitations on permitted business activities;
limitations on mergers and acquisitions;
limitations on investments;
limitations on transactions with affiliates; and
maintenance of commercially reasonable insurance coverage.
A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.
Compliance with our Covenants
We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.

7.LEGACY ETP PREFERRED UNITS:
The Legacy ETP Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and were reflected as long-term liabilities in our consolidated balance sheets. The Legacy ETP Preferred Units were entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record dates of the Partnership’s common unit distributions. In January 2017, ETP repurchased all of its 1.9 million outstanding Legacy ETP Preferred Units for cash in the aggregate amount of $53 million.

8.EQUITY:
Limited Partner interests are represented by Common, Class E Units, Class G Units, Class I Units, Class J Units and Class K Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s outstanding securities also include preferred units, as described below. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance.

IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs.
Common Units
The change in Common Units was as follows:
 Years Ended December 31,
 
2017 (1)
 
2016 (1)
 
2015 (1)
Number of Common Units, beginning of period794.8
 758.5
 533.4
Common Units redeemed in connection with certain transactions—
 (26.7) (77.8)
Common Units issued in connection with public offerings54.0
 —
 —
Common Units issued in connection with certain acquisitions—
 13.3
 258.2
Common Units issued in connection with the Distribution Reinvestment Plan12.0
 9.9
 11.7
Common Units issued in connection with Equity Distribution Agreements22.6
 39.0
 31.7
Common Units issued to ETE in a private placement transaction23.7
 —
 —
Common Unit increase from Sunoco Logistics Merger (2)255.4
 —
 —
Issuance of Common Units under equity incentive plans1.6
 0.8
 1.3
Number of Common Units, end of period1,164.1
 794.8
 758.5
(1)
The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
(2) 
Represents the effective date. These forward-starting swaps have termsSunoco Logistics common units outstanding at the close of 10 years with a mandatory termination date the same asSunoco Logistics Merger. See Note 1 for discussion on the effective date.
(3)
Representsaccounting treatment of the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
(4)
Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.Sunoco Logistics Merger.
Credit Risk
Credit risk refersOur Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the riskLimited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”
Equity Distribution Program
From time to time, we have sold Common Units through equity distribution agreements. Such sales of Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreements.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion.
During the year ended December 31, 2017, we issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $752 million of our Common Units remained available to be issued under our currently effective equity distribution agreement.
Equity Incentive Plan Activity
We issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may default on its contractual obligationselect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.

Distribution Reinvestment Program
Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, the Partnership initiated a new distribution reinvestment plan.
During the years ended December 31, 2017, 2016 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units.
As of December 31, 2017, a losstotal of 20.8 million Common Units remain available to be issued under the existing registration statement.
August 2017 Units Offering
In August 2017, the Partnership issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by the Partnership to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.
January 2017 Private Placement
In January 2017, the Partnership sold 23.7 million ETP Common Units to ETE in a private placement transaction for gross proceeds of approximately $568 million.
Class E Units
There are currently 8.9 million Class E Units outstanding, all of which are currently owned by HHI. The Class E Units generally do not have any voting rights. The Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the Class E Units at a future date.
Class G Units
There are currently 90.7 million Class G Units outstanding, all of which are held by a wholly-owned subsidiary of the Partnership. The Class G Units generally do not have any voting rights. The Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class G Unit per year. Allocations of depreciation and amortization to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may at times require collateral under certain circumstances to mitigate credit risk as necessary. We also implement the use of industry standard commercial agreements which allowClass G Units for the netting of positive and negative exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities and midstream companies. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
We have maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin depositstax purposes are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded

S - 60

derivatives, and we exchange margin callsbased on a daily basis for exchange traded transactions. Since the margin callspredetermined percentage and are made daily with the exchange brokers, the fair value of the financial derivative instrumentsnot contingent on whether ETP has net income or loss. These units are deemed current and netted in deposits paid to vendors within other current assetsreflected as treasury units in the consolidated balance sheets.financial statements.
For financial instruments, failureClass H Units
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a counterpartynew class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to perform on a contract could result(i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.
Class I Units
In connection with the Bakken Pipeline Transaction discussed in Note 3, in April 2015, ETP issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the

cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our inabilityPartnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to realize amountsthe April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
Class K Units
On December 29, 2016, the Partnership issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in the Partnership, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco.  If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2017, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETP.
Sales of Common Units by legacy Sunoco Logistics
Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.
In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated.
ETP Preferred Units
In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit.
Distributions on the Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation

preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.
Quarterly Distributions of Available Cash
Under the Partnership’s limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that have been recorded on our consolidated balance sheetsit determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and recognizedpayment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in net income or other comprehensive income.a quarter, the holders of the incentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”
Derivative Summary
The following table provides a summaryshows the target distribution levels and distribution “splits” between the general and limited partners and the holders of our derivative assets and liabilities:the Partnership’s incentive distribution rights (”IDRs”):
 Fair Value of Derivative Instruments
 Asset Derivatives Liability Derivatives
 December 31, 2014 December 31, 2013 December 31, 2014 December 31, 2013
Derivatives designated as hedging instruments:       
Commodity derivatives (margin deposits)$43
 $3
 $—
 $(18)
 43
 3
 —
 (18)
Derivatives not designated as hedging instruments:       
Commodity derivatives (margin deposits)617
 227
 (577) (209)
Commodity derivatives23
 39
 (23) (38)
Interest rate derivatives3
 47
 (155) (95)
 643
 313
 (755) (342)
Total derivatives$686
 $316
 $(755) $(360)
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount IDRs 
Partners (1)
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%
(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:
Quarter Ended ETP Sunoco Logistics
December 31, 2014 $0.6633
 $0.4000
March 31, 2015 0.6767
 0.4190
June 30, 2015 0.6900
 0.4380
September 30, 2015 0.7033
 0.4580
December 31, 2015 0.7033
 0.4790
March 31, 2016 0.7033
 0.4890
June 30, 2016 0.7033
 0.5000
September 30, 2016 0.7033
 0.5100
December 31, 2016 0.7033
 0.5200

Distributions on common units declared and paid by Post-Merger ETP were as follows:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 16, 2017 $0.5350
June 30, 2017 August 7, 2017 August 15, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
December 31, 2017 February 8, 2018 February 14, 2018 0.5650
In connection with previous transactions, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods:
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Distributions declared and paid by ETP to the preferred unitholders were as follows:
 Distribution per Preferred Unit
Quarter Ended Record Date Payment Date Series A Series B
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
 $16.378
Accumulated Other Comprehensive Income
The following table presents the fair valuecomponents of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:AOCI, net of tax:
    Asset Derivatives Liability Derivatives
  Balance Sheet Location December 31, 2014 December 31, 2013 December 31, 2014 December 31, 2013
Derivatives in offsetting agreements:        
OTC contracts Price risk management assets (liabilities) $23
 $41
 $(23) $(38)
Broker cleared derivative contracts Other current assets 674
 265
 (574) (318)
  697
 306
 (597) (356)
Offsetting agreements:        
Counterparty netting Price risk management assets (liabilities) (19) (36) 19
 36
Payments on margin deposit Other current assets 5
 (1) (22) 55
  (14) (37) (3) 91
Net derivatives with offsetting agreements 683
 269
 (600) (265)
Derivatives without offsetting agreements 3
 47
 (155) (95)
Total derivatives $686
 $316
 $(755) $(360)
 December 31,
 2017 2016
Available-for-sale securities$8
 $2
Foreign currency translation adjustment(5) (5)
Actuarial gain related to pensions and other postretirement benefits(5) 7
Investments in unconsolidated affiliates, net5
 4
Total AOCI, net of tax$3
 $8
We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

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The following tables summarizetable below sets forth the tax amounts recognized with respect to our derivative financial instruments:included in the respective components of other comprehensive income:
 Change in Value Recognized in OCI on Derivatives (Effective Portion)
 Years Ended December 31,
 2014 2013 2012
Derivatives in cash flow hedging relationships:     
Commodity derivatives$—
 $(1) $8
Total$—
 $(1) $8
 December 31,
 2017 2016
Available-for-sale securities$(2) $(2)
Foreign currency translation adjustment3
 3
Actuarial loss relating to pension and other postretirement benefits3
 —
Total$4
 $1
 Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
   Years Ended December 31,
   2014 2013 2012
Derivatives in cash flow hedging relationships:       
Commodity derivativesCost of products sold $(3) $4
 $14
Total  $(3) $4
 $14
 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
   Years Ended December 31,
   2014 2013 2012
Derivatives in fair value hedging relationships (including hedged item):       
Commodity derivativesCost of products sold $(8) $8
 $54
Total  $(8) $8
 $54
 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives
   Years Ended December 31,
   2014 2013 2012
Derivatives not designated as hedging instruments:       
Commodity derivatives – TradingCost of products sold $(6) $(11) $(7)
Commodity derivatives – Non-tradingCost of products sold 106
 (12) (15)
Commodity contracts – Non-tradingDeferred gas purchases —
 (3) (26)
Interest rate derivativesGains (losses) on interest rate derivatives (157) 44
 (4)
Total  $(57) $18
 $(52)

13.9.RETIREMENT BENEFITS:UNIT-BASED COMPENSATION PLANS:
Savings and Profit Sharing PlansETP Unit-Based Compensation Plan
We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees. Employer matching contributions are calculated using a formula based on employee contributions. We

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and our subsidiaries made matching contributions of $50 million, $38 million and $21 million to these 401(k) savingshave issued equity incentive plans for the years ended employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent

rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2014, 2013 and 2012, respectively.2017, an aggregate total of 8.4 million ETP Common Units remain available to be awarded under our equity incentive plans.
Pension and Other Postretirement Benefit Plans
Panhandle
Postretirement benefits expense for the years ended December 31, 2017, 2016, and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that were available tocovered substantially all of its employees, pendingemployees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree meeting certain age and service requirements.medical benefits were no longer offered to union employees.
Sunoco, Inc.
Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and anticipates approval for the distribution of assets from the plan, pending approval from the Pension Benefit Guaranty Corporationpaid lump sums to eligible active and the IRS,terminated vested participants in the fourth quarter ofDecember 2015.
Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200$200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.

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Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.

The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Pension Benefits   Pension Benefits  Pension Benefits   Pension Benefits  
Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement BenefitsFunded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Change in benefit obligation:                      
Benefit obligation at beginning of period$632
 $61
 $223
 $1,117
 $78
 $296
$18
 $51
 $166
 $20
 $57
 $181
Service cost—
 —
 —
 3
 —
 —
Interest cost28
 3
 5
 33
 2
 6
1
 1
 4
 1
 2
 4
Amendments—
 —
 1
 —
 —
 2
—
 —
 7
 —
 —
 —
Benefits paid, net(45) (9) (28) (99) (16) (26)(2) (6) (20) (1) (7) (21)
Actuarial (gain) loss and other130
 10
 2
 (74) (3) (14)2
 1
 (1) (2) (1) 2
Settlements(27) —
 —
 (95) —
 —
(18) —
 —
 —
 —
 —
Dispositions—
 —
 (1) (253) —
 (41)
Benefit obligation at end of period718
 65
 202
 632
 61
 223
$1
 $47
 $156
 $18
 $51
 $166
                      
Change in plan assets:                      
Fair value of plan assets at beginning of period600
 —
 284
 906
 —
 312
$12
 $—
 $256
 $15
 $—
 $261
Return on plan assets and other70
 —
 6
 43
 —
 17
3
 —
 11
 (2) —
 6
Employer contributions—
 —
 8
 —
 —
 8
6
 —
 10
 —
 —
 10
Benefits paid, net(45) —
 (28) (99) —
 (26)(2) —
 (20) (1) —
 (21)
Settlements(27) —
 —
 (95) —
 —
(18) —
 —
 —
 —
 —
Dispositions—
 —
 (5) (155) —
 (27)
Fair value of plan assets at end of period598
 —
 265
 600
 —
 284
$1
 $—
 $257
 $12
 $—
 $256
                      
Amount underfunded (overfunded) at end of period$120
 $65
 $(63) $32
 $61
 $(61)$—
 $47
 $(101) $6
 $51
 $(90)
                      
Amounts recognized in the consolidated balance sheets consist of:                      
Non-current assets$—
 $—
 $90
 $—
 $—
 $86
$—
 $—
 $127
 $—
 $—
 $114
Current liabilities—
 (9) (2) —
 (9) (2)—
 (8) (2) —
 (7) (2)
Non-current liabilities(120) (56) (25) (32) (52) (23)—
 (39) (24) (6) (44) (23)
$(120) $(65) $63
 $(32) $(61) $61
$—
 $(47) $101
 $(6) $(51) $89
                      
Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of:                      
Net actuarial gain$18
 $7
 $(20) $(86) $(4) $(25)$—
 $5
 $(18) $—
 $—
 $(13)
Prior service cost—
 —
 17
 —
 —
 18
—
 —
 21
 —
 —
 15
$18
 $7
 $(3) $(86) $(4) $(7)$—
 $5
 $3
 $—
 $—
 $2

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The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Pension Benefits   Pension Benefits  Pension Benefits   Pension Benefits  
Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement BenefitsFunded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Projected benefit obligation$718
 $65
 N/A
 $632
 61
 N/A
$1
 $47
 N/A
 $18
 $51
 N/A
Accumulated benefit obligation718
 65
 202
 632
 61
 $223
1
 47
 $156
 18
 51
 $166
Fair value of plan assets598
 —
 265
 600
 —
 284
1
 —
 257
 12
 —
 256
Components of Net Periodic Benefit Cost
 December 31, 2014 December 31, 2013
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Net periodic benefit cost:       
Service cost$—
 $—
 $3
 $—
Interest cost31
 5
 35
 6
Expected return on plan assets(40) (8) (54) (9)
Prior service cost amortization—
 1
 —
 1
Actuarial loss amortization(1) (1) 2
 —
Settlements(4) —
 (2) —
 (14) (3) (16) (2)
Regulatory adjustment(1)
—
 —
 5
 —
Net periodic benefit cost$(14) $(3) $(11) $(2)
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Net Periodic Benefit Cost:       
Interest cost$2
 $4
 $3
 $4
Expected return on plan assets—
 (9) (1) (8)
Prior service cost amortization—
 2
 —
 1
Net periodic benefit cost$2
 $(3) $2
 $(3)
(1)
Southern Union, the predecessor of Panhandle, historically recovered certain qualified pension benefit plan and other postretirement benefit plan costs through rates charged to utility customers in its distribution operations.  Certain utility commissions require that the recovery of these costs be based on the Employee Retirement Income Security Act of 1974, as amended, or other utility commission specific guidelines.  The difference between these regulatory-based amounts and the periodic benefit cost calculated pursuant to GAAP is deferred as a regulatory asset or liability and amortized to expense over periods in which this difference will be recovered in rates, as promulgated by the applicable utility commission.
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement BenefitsPension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.62% 2.24% 4.65% 2.33%3.27% 2.34% 3.65% 2.34%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
N/A
 N/A
 N/A
 N/A

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The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
December 31, 2014 December 31, 2013December 31, 2017 December 31, 2016
Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement BenefitsPension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate4.65% 3.02% 3.50% 2.68%3.52% 3.10% 3.60% 3.06%
Expected return on assets:              
Tax exempt accounts7.50% 7.00% 7.50% 6.95%3.50% 7.00% 3.50% 7.00%
Taxable accountsN/A
 4.50% N/A
 4.42%N/A
 4.50% N/A
 4.50%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
N/A
 N/A
 N/A
 N/A
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest

rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by PanhandlePanhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:
 December 31,December 31,
 2014 20132017 2016
Health care cost trend rate 7.09% 7.57%7.20% 6.73%
Rate to which the cost trend is assumed to decline (the ultimate trend rate) 5.41% 5.42%4.99% 4.96%
Year that the rate reaches the ultimate trend rate 2018
 2018
2023
 2021
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification.  To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of up to 10%.
The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.
The fair value of the pension plan assets by asset category at the dates indicated is as follows:
   Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy
 Fair Value as of December 31, 2014 Level 1 Level 2 Level 3
Asset category:       
Cash and cash equivalents$25
 $25
 $—
 $—
Mutual funds(1)
110
 —
 110
 —
Fixed income securities463
 —
 463
 —
Total$598
 $25
 $573
 $—
    Fair Value Measurements at December 31, 2017
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Mutual funds (1)
 $1
 $1
 $—
 $—
Total $1
 $1
 $—
 $—

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(1)
Primarily comprisedComprised of approximately 100% equities as of December 31, 2014.2017.
   Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy
 Fair Value as of December 31, 2013 Level 1 Level 2 Level 3
Asset category:       
Cash and cash equivalents$12
 $12
 $—
 $—
Mutual funds(1)
368
 —
 281
 87
Fixed income securities220
 —
 220
 —
Total$600
 $12
 $501
 $87
    Fair Value Measurements at December 31, 2016
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Mutual funds (1)
 $12
 $12
 $—
 $—
Total $12
 $12
 $—
 $—
(1) 
Primarily comprisedComprised of approximately 41%100% equities 45% fixed income securities, and 14% in other investments as of December 31, 2013.2016.

The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
   Fair Value Measurements at December 31, 2014 Using Fair Value Hierarchy
 Fair Value as of December 31, 2014 Level 1 Level 2 Level 3
Asset category:       
Cash and cash equivalents$9
 $9
 $—
 $—
Mutual funds(1)
131
 131
 —
 —
Fixed income securities125
 —
 125
 —
Total$265
 $140
 $125
 $—
    Fair Value Measurements at December 31, 2017
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $33
 $33
 $—
 $—
Mutual funds (1)
 154
 154
 —
 —
Fixed income securities 70
 —
 70
 —
Total $257
 $187
 $70
 $—
(1)
Primarily comprised of approximately 38% equities, 61% fixed income securities and 2% cash as of December 31, 2017.
    Fair Value Measurements at December 31, 2016
  Fair Value Total Level 1 Level 2 Level 3
Asset Category:        
Cash and Cash Equivalents $23
 $23
 $—
 $—
Mutual funds (1)
 142
 142
 —
 —
Fixed income securities 91
 —
 91
 —
Total $256
 $165
 $91
 $—
(1) 
Primarily comprised of approximately 56%31% equities, 38%66% fixed income securities and 6%3% cash as of December 31, 2014.2016.
   Fair Value Measurements at December 31, 2013 Using Fair Value Hierarchy
 Fair Value as of December 31, 2013 Level 1 Level 2 Level 3
Asset category:       
Cash and cash equivalents$10
 $10
 $—
 $—
Mutual funds(1)
130
 112
 18
 —
Fixed income securities144
 —
 144
 —
Total$284
 $122
 $162
 $—
(1)
Primarily comprised of approximately 41% equities, 48% fixed income securities, 6% cash, and 5% in other investments as of December 31, 2013.
The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines.  See Note 2for information related to the framework used to measure the fair value of its pension and other postretirement plan assets.
Contributions
We expect to contribute approximately $129$8 million to pension plans and approximately $10 million to other postretirement plans in 2015.2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.

S - 67

Benefit Payments
PanhandlePanhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:
  Pension Benefits  
Years Funded Plans Unfunded Plans Other Postretirement Benefits (Gross, Before Medicare Part D)
2015 $717
 $9
 $28
2016 —
 8
 26
2017 —
 7
 25
2018 —
 7
 23
2019 —
 6
 22
2020 – 2024 —
 23
 65
Years 
Pension Benefits - Unfunded Plans (1)
 Other Postretirement Benefits (Gross, Before Medicare Part D)
2018 $8
 $24
2019 6
 23
2020 6
 21
2021 5
 19
2022 4
 17
2023 – 2027 15
 37
(1)     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.

14.RELATED PARTY TRANSACTIONS:
In June 2017, ETP acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8.
ETE has agreements with subsidiariespreviously paid ETP to provide or receiveservices on its behalf and on behalf of other subsidiaries of ETE, which included the reimbursement of various operating and general and administrative expenses incurred by ETP on behalf of ETE and its subsidiaries. These agreements expired in 2016.
In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million and $290 million during the years ended December 31, 2017, 2016 and 2015, respectively.
15.REPORTABLE SEGMENTS:
Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP;
Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
Corporate and Other, including the following:
activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented.
The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements.
We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.
Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.

Eliminations in the tables below include the following:
MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above.
 Years Ended December 31,
 2017 2016 2015
Revenues:     
Investment in ETP:     
Revenues from external customers$28,613
 $21,618
 $34,156
Intersegment revenues441
 209
 136
 29,054
 21,827
 34,292
Investment in Sunoco LP:     
Revenues from external customers11,713
 9,977
 12,419
Intersegment revenues10
 9
 11
 11,723
 9,986
 12,430
Investment in Lake Charles LNG:     
Revenues from external customers197
 197
 216
 

 

 

Adjustments and Eliminations:(451) (218) (10,842)
Total revenues$40,523
 $31,792
 $36,096
      
Costs of products sold:     
Investment in ETP$20,801
 $15,080
 $26,714
Investment in Sunoco LP10,615
 8,830
 11,450
Adjustments and Eliminations(450) (217) (9,496)
Total costs of products sold$30,966
 $23,693
 $28,668
      
Depreciation, depletion and amortization:     
Investment in ETP$2,332
 $1,986
 $1,929
Investment in Sunoco LP169
 176
 150
Investment in Lake Charles LNG39
 39
 39
Corporate and Other14
 15
 17
Adjustments and Eliminations—
 —
 (184)
Total depreciation, depletion and amortization$2,554
 $2,216
 $1,951
 Years Ended December 31,
 2017 2016 2015
Equity in earnings of unconsolidated affiliates:     
Investment in ETP$156
 $59
 $469
Adjustments and Eliminations(12) 211
 (193)
Total equity in earnings of unconsolidated affiliates$144
 $270
 $276

 Years Ended December 31,
 2017 2016 2015
Segment Adjusted EBITDA:     
Investment in ETP$6,712
 $5,733
 $5,517
Investment in Sunoco LP732
 665
 719
Investment in Lake Charles LNG175
 179
 196
Corporate and Other(31) (170) (104)
Adjustments and Eliminations(268) (272) (590)
Total Segment Adjusted EBITDA7,320
 6,135
 5,738
Depreciation, depletion and amortization(2,554) (2,216) (1,951)
Interest expense, net of interest capitalized(1,922) (1,804) (1,622)
Gains on acquisitions—
 83
 —
Impairment of investments in unconsolidated affiliates(313) (308) —
Impairment losses(1,039) (1,040) (339)
Losses on interest rate derivatives(37) (12) (18)
Non-cash unit-based compensation expense(99) (70) (91)
Unrealized gains (losses) on commodity risk management activities59
 (136) (65)
Losses on extinguishments of debt(89) —
 (43)
Inventory valuation adjustments24
 97
 (67)
Adjusted EBITDA related to discontinued operations(223) (199) (228)
Adjusted EBITDA related to unconsolidated affiliates(716) (675) (713)
Equity in earnings of unconsolidated affiliates144
 270
 276
Other, net155
 79
 23
Income from continuing operations before income tax benefit$710
 $204
 $900
Income tax benefit from continuing operations(1,833) (258) (123)
Income from continuing operations2,543
 462
 1,023
Income (loss) from discontinued operations, net of tax(177) (462) 38
Net income$2,366
 $—
 $1,061
 December 31,
 2017 2016 2015
Total assets:     
Investment in ETP$77,965
 $70,105
 $65,128
Investment in Sunoco LP8,344
 8,701
 8,842
Investment in Lake Charles LNG1,646
 1,508
 1,369
Corporate and Other598
 711
 638
Adjustments and Eliminations(2,307) (2,100) (4,833)
Total$86,246
 $78,925
 $71,144

 Years Ended December 31,
 2017 2016 2015
Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):     
Investment in ETP$5,901
 $5,810
 $8,167
Investment in Sunoco LP103
 119
 178
Investment in Lake Charles LNG2
 —
 1
Adjustments and Eliminations—
 —
 (123)
Total$6,006
 $5,929
 $8,223
 December 31,
 2017 2016 2015
Advances to and investments in affiliates:     
Investment in ETP$3,816
 $4,280
 $5,003
Adjustments and Eliminations(1,111) (1,240) (1,541)
Total$2,705
 $3,040
 $3,462
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP.
Investment in ETP
 Years Ended December 31,
 2017 2016 2015
Intrastate Transportation and Storage$2,891
 $2,155
 $1,912
Interstate Transportation and Storage915
 946
 1,008
Midstream2,510
 2,342
 2,607
NGL and refined products transportation and services8,326
 5,973
 4,569
Crude oil transportation and services11,672
 7,539
 8,980
All Other2,740
 2,872
 15,216
Total revenues29,054
 21,827
 34,292
Less: Intersegment revenues441
 209
 136
Revenues from external customers$28,613
 $21,618
 $34,156
Investment in Sunoco LP
 Years Ended December 31,
 2017 2016 2015
Retail operations$2,263
 $1,991
 $2,226
Wholesale operations9,460
 7,995
 10,204
Total revenues11,723
 9,986
 12,430
Less: Intersegment revenues10
 9
 11
Revenues from external customers$11,713
 $9,977
 $12,419
Investment in Lake Charles LNG
Lake Charles LNG’s revenues of $197 million, $197 million and $216 million for the years ended December 31, 2017, 2016 and 2015, respectively, were related to LNG terminalling.

16.QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year.
 Quarters Ended  
 March 31* June 30* September 30* December 31 Total Year
2017:         
Revenues$9,660
 $9,427
 $9,984
 $11,452
 $40,523
Operating income (loss)758
 746
 924
 285
 2,713
Net income (loss)319
 121
 758
 1,168
 2,366
Limited Partners’ interest in net income232
 204
 240
 239
 915
Basic net income per limited partner unit$0.22
 $0.18
 $0.22
 $0.22
 $0.85
Diluted net income per limited partner unit$0.21
 $0.18
 $0.22
 $0.22
 $0.83
 Quarters Ended  
 March 31* June 30* September 30* December 31* Total Year*
2016:         
Revenues$6,447
 $7,866
 $8,156
 $9,323
 $31,792
Operating income680
 814
 624
 (275) 1,843
Net income (loss)320
 417
 (3) (734) —
Limited Partners’ interest in net income311
 239
 207
 226
 983
Basic net income per limited partner unit$0.30
 $0.23
 $0.20
 $0.22
 $0.94
Diluted net income per limited partner unit$0.30
 $0.23
 $0.19
 $0.21
 $0.92
* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.
The three months ended December 31, 2017 and 2016 reflected the recognition of impairment losses of $1.04 billion and $1.04 billion, respectively. Impairment losses in 2017 were primarily related to ETP’s interstate transportation and storage operations, NGL and refined products operations and other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ETP’s interstate transportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. The three months ended December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of ETP’s investments in subsidiaries of $313 million and $308 million, respectively, in its interstate transportation and storage operations.

17.SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:
Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:
BALANCE SHEETS
 December 31,
 2017 2016
ASSETS   
CURRENT ASSETS:   
Cash and cash equivalents$1
 $2
Accounts receivable from related companies65
 55
Other current assets1
 —
Total current assets67
 57
PROPERTY, PLANT AND EQUIPMENT, net27
 36
ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES6,082
 5,088
INTANGIBLE ASSETS, net—
 1
GOODWILL9
 9
OTHER NON-CURRENT ASSETS, net8
 10
Total assets$6,193
 $5,201
LIABILITIES AND PARTNERS’ CAPITAL   
CURRENT LIABILITIES:   
Accounts payable$—
 $1
Accounts payable to related companies—
 22
Interest payable66
 66
Accrued and other current liabilities4
 3
Total current liabilities70
 92
LONG-TERM DEBT, less current maturities6,700
 6,358
NOTE PAYABLE TO AFFILIATE617
 443
OTHER NON-CURRENT LIABILITIES2
 2
    
COMMITMENTS AND CONTINGENCIES
 
    
PARTNERS’ DEFICIT:   
General Partner(3) (3)
Limited Partners:   
Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)(1,643) (1,871)
Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016)450
 180
Total partners’ deficit(1,196) (1,694)
Total liabilities and partners’ deficit$6,193
 $5,201


STATEMENTS OF OPERATIONS
 Years Ended December 31,
 2017 2016 2015
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES$(31) $(185) $(112)
OTHER INCOME (EXPENSE):     
Interest expense, net of interest capitalized(347) (327) (294)
Equity in earnings of unconsolidated affiliates1,381
 1,511
 1,601
Loss on extinguishment of debt(47) —
 —
Other, net(2) (4) (5)
INCOME BEFORE INCOME TAXES954
 995
 1,190
Income tax expense—
 —
 1
NET INCOME954
 995
 1,189
General Partner’s interest in net income2
 3
 3
Convertible Unitholders’ interest in income37
 9
 —
Class D Unitholder’s interest in net income—
 —
 3
Limited Partners’ interest in net income$915
 $983
 $1,183


STATEMENTS OF CASH FLOWS
 Years Ended December 31,
 2017 2016 2015
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES$831
 $918
 $1,103
CASH FLOWS FROM INVESTING ACTIVITIES:     
Cash paid for Bakken Pipeline Transaction—
 —
 (817)
Contributions to unconsolidated affiliates(861) (70) —
Capital expenditures(1) (16) (19)
Contributions in aid of construction costs7
 —
 —
Net cash used in investing activities(855) (86) (836)
CASH FLOWS FROM FINANCING ACTIVITIES:     
Proceeds from borrowings2,219
 225
 3,672
Principal payments on debt(1,881) (210) (1,985)
Distributions to partners(1,010) (1,022) (1,090)
Proceeds from affiliate174
 176
 210
Common Units issued for cash568
 —
 —
Units repurchased under buyback program—
 —
 (1,064)
Debt issuance costs(47) —
 (11)
Net cash provided by (used in) financing activities23
 (831) (268)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS(1) 1
 (1)
CASH AND CASH EQUIVALENTS, beginning of period2
 1
 2
CASH AND CASH EQUIVALENTS, end of period$1
 $2
 $1


ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS
OF CERTAIN SUBSIDIARIES INCLUDED PURSUANT
TO RULE 3-16 OF REGULATION S-X
Page
1. Energy Transfer Partners, L.P. Financial StatementsS - 2


1.ENERGY TRANSFER PARTNERS, L.P. FINANCIAL STATEMENTS


INDEX TO FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting FirmS - 3
Consolidated Balance Sheets – December 31, 2017 and 2016S - 4
Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 and 2015S - 6
Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 and 2015S - 7
Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 and 2015S - 8
Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 and 2015S - 10
Notes to Consolidated Financial StatementsS - 12

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


Board of Directors of Energy Transfer Partners, L.L.C. and
Unitholders of Energy Transfer Partners, L.P.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 23, 2018 (not separately included herein) expressed an unqualified opinion thereon.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2004.

Dallas, Texas
February 23, 2018


ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
ASSETS   
Current assets:   
Cash and cash equivalents$306
 $360
Accounts receivable, net3,946
 3,002
Accounts receivable from related companies318
 209
Inventories1,589
 1,626
Income taxes receivable135
 128
Derivative assets24
 20
Other current assets210
 298
Total current assets6,528
 5,643
    
Property, plant and equipment67,699
 58,220
Accumulated depreciation and depletion(9,262) (7,303)
 58,437
 50,917
    
Advances to and investments in unconsolidated affiliates3,816
 4,280
Other non-current assets, net758
 672
Intangible assets, net5,311
 4,696
Goodwill3,115
 3,897
Total assets$77,965
 $70,105
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 December 31,
 2017 2016*
LIABILITIES AND EQUITY   
Current liabilities:   
Accounts payable$4,126
 $2,900
Accounts payable to related companies209
 43
Derivative liabilities109
 166
Accrued and other current liabilities2,143
 1,905
Current maturities of long-term debt407
 1,189
Total current liabilities6,994
 6,203
    
Long-term debt, less current maturities32,687
 31,741
Long-term notes payable – related company—
 250
Non-current derivative liabilities145
 76
Deferred income taxes2,883
 4,394
Other non-current liabilities1,084
 952
    
Commitments and contingencies
 

Legacy ETP Preferred Units—
 33
Redeemable noncontrolling interests21
 15
    
Equity:   
Series A Preferred Units (950,000 units authorized, issued and outstanding as of December 31, 2017)944
 —
Series B Preferred Units (550,000 units authorized, issued and outstanding as of December 31, 2017)547
 —
Limited Partners:   
Common Unitholders (1,164,112,575 and 794,803,854 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively)26,531
 14,925
Class E Unitholder (8,853,832 units authorized, issued and outstanding – held by subsidiary)—
 —
Class G Unitholder (90,706,000 units authorized, issued and outstanding – held by subsidiary)—
 —
Class H Unitholder (81,001,069 units authorized, issued and outstanding as of December 31, 2016)—
 3,480
Class I Unitholder (100 units authorized, issued and outstanding)—
 2
Class K Unitholders (101,525,429 units authorized, issued and outstanding – held by subsidiaries)—
 —
General Partner244
 206
Accumulated other comprehensive income3
 8
Total partners’ capital28,269
 18,621
Noncontrolling interest5,882
 7,820
Total equity34,151
 26,441
Total liabilities and equity$77,965
 $70,105
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
 Years Ended December 31,
 2017 2016* 2015*
REVENUES:     
Natural gas sales$4,172
 $3,619
 $3,671
NGL sales6,972
 4,841
 3,936
Crude sales10,184
 6,766
 8,378
Gathering, transportation and other fees4,265
 4,003
 3,997
Refined product sales (see Note 3)1,515
 1,047
 9,958
Other (see Note 3)1,946
 1,551
 4,352
Total revenues29,054
 21,827
 34,292
COSTS AND EXPENSES:     
Cost of products sold (see Note 3)20,801
 15,080
 26,714
Operating expenses (see Note 3)2,170
 1,839
 2,608
Depreciation, depletion and amortization2,332
 1,986
 1,929
Selling, general and administrative (see Note 3)434
 348
 475
Impairment losses920
 813
 339
Total costs and expenses26,657
 20,066
 32,065
OPERATING INCOME2,397
 1,761
 2,227
OTHER INCOME (EXPENSE):     
Interest expense, net(1,365) (1,317) (1,291)
Equity in earnings from unconsolidated affiliates156
 59
 469
Impairment of investments in unconsolidated affiliates(313) (308) —
Gains on acquisitions—
 83
 —
Losses on extinguishments of debt(42) —
 (43)
Losses on interest rate derivatives(37) (12) (18)
Other, net209
 131
 22
INCOME BEFORE INCOME TAX BENEFIT1,005
 397
 1,366
Income tax benefit(1,496) (186) (123)
NET INCOME2,501
 583
 1,489
Less: Net income attributable to noncontrolling interest420
 295
 134
Less: Net loss attributable to predecessor—
 —
 (34)
NET INCOME ATTRIBUTABLE TO PARTNERS2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)$986
 $(1,019) $(27)
NET INCOME (LOSS) PER COMMON UNIT:     
Basic$0.94
 $(1.38) $(0.07)
Diluted$0.93
 $(1.38) $(0.08)
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
Net income$2,501
 $583
 $1,489
Other comprehensive income (loss), net of tax:     
Change in value of available-for-sale securities6
 2
 (3)
Actuarial gain (loss) relating to pension and other postretirement benefits(12) (1) 65
Foreign currency translation adjustment—
 (1) (1)
Change in other comprehensive income (loss) from unconsolidated affiliates1
 4
 (1)
 (5) 4
 60
Comprehensive income2,496
 587
 1,549
Less: Comprehensive income attributable to noncontrolling interest420
 295
 134
Less: Comprehensive loss attributable to predecessor—
 —
 (34)
Comprehensive income attributable to partners$2,076
 $292
 $1,449
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
     Limited Partners          
 Series A Preferred Units Series B Preferred Units Common Unit holders Class H Units Class I Units General
Partner		 
Accumulated
Other
Comprehensive
Income (Loss)
 
Non-controlling
Interest
 Predecessor Equity Total
Balance, December 31, 2014*$—
 $—
 $10,427
 $1,512
 $—
 $184
 $(56) $5,143
 $8,088
 $25,298
Distributions to partners—
 —
 (1,863) (247) (80) (944) —
 —
 —
 (3,134)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (338) —
 (338)
Units issued for cash—
 —
 1,428
 —
 —
 —
 —
 —
 —
 1,428
Subsidiary units issued for cash—
 —
 298
 —
 —
 2
 —
 1,219
 —
 1,519
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 875
 —
 875
Bakken Pipeline Transaction—
 —
 (999) 1,946
 —
 —
 —
 72
 —
 1,019
Sunoco LP Exchange Transaction—
 —
 (52) —
 —
 —
 —
 (940) —
 (992)
Susser Exchange Transaction—
 —
 (68) —
 —
 —
 —
 —
 —
 (68)
Acquisition and disposition of noncontrolling interest—
 —
 (26) —
 —
 —
 —
 (39) —
 (65)
Predecessor distributions to partners—
 —
 —
 —
 —
 —
 —
 —
 (202) (202)
Predecessor units issued for cash—
 —
 —
 —
 —
 —
 —
 —
 34
 34
Regency Merger—
 —
 7,890
 —
 —
 —
 —
 —
 (7,890) —
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 60
 —
 —
 60
Other, net—
 —
 23
 —
 —
 —
 —
 36
 4
 63
Net income (loss)—
 —
 (27) 258
 94
 1,064
 —
 134
 (34) 1,489
Balance, December 31, 2015*—
 —
 17,031
 3,469
 14
 306
 4
 6,162
 —
 26,986
Distributions to partners—
 —
 (2,134) (340) (20) (1,048) —
 —
 —
 (3,542)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (481) —
 (481)
Units issued for cash—
 —
 1,098
 —
 —
 —
 —
 —
 —
 1,098
Subsidiary units issued—
 —
 37
 —
 —
 —
 —
 1,351
 —
 1,388

Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 236
 —
 236
Sunoco, Inc. retail business to Sunoco LP transaction—
 —
 (405) —
 —
 —
 —
 —
 —
 (405)
PennTex Acquisition—
 —
 307
 —
 —
 —
 —
 236
 —
 543
Other comprehensive income, net of tax—
 —
 —
 —
 —
 —
 4
 —
 —
 4
Other, net—
 —
 10
 —
 —
 —
 —
 21
 —
 31
Net income (loss)—
 —
 (1,019) 351
 8
 948
 —
 295
 —
 583
Balance, December 31, 2016*—
 —
 14,925
 3,480
 2
 206
 8
 7,820
 —
 26,441
Distributions to partners—
 —
 (2,419) (95) (2) (952) —
 —
 —
 (3,468)
Distributions to noncontrolling interest—
 —
 —
 —
 —
 —
 —
 (430) —
 (430)
Units issued for cash937
 542
 2,283
 —
 —
 —
 —
 —
 —
 3,762
Sunoco Logistics Merger—
 —
 9,416
 (3,478) —
 —
 —
 (5,938) —
 —
Capital contributions from noncontrolling interest—
 —
 —
 —
 —
 —
 —
 2,202
 —
 2,202
Sale of Bakken Pipeline interest—
 —
 1,260
 —
 —
 —
 —
 740
 —
 2,000
Sale of Rover Pipeline interest—
 —
 93
 —
 —
 —
 —
 1,385
 —
 1,478
Acquisition of PennTex noncontrolling interest—
 —
 (48) —
 —
 —
 —
 (232) —
 (280)
Other comprehensive loss, net of tax—
 —
 —
 —
 —
 —
 (5) —
 —
 (5)
Other, net—
 —
 35
 —
 —
 —
 —
 (85) —
 (50)
Net income7
 5
 986
 93
 —
 990
 —
 420
 —
 2,501
Balance, December 31, 2017$944
 $547
 $26,531
 $—
 $—
 $244
 $3
 $5,882
 $—
 $34,151
* As adjusted. See Note 2.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Years Ended December 31,
 2017 2016* 2015*
OPERATING ACTIVITIES:     
Net income$2,501
 $583
 $1,489
Reconciliation of net income to net cash provided by operating activities:     
Depreciation, depletion and amortization2,332
 1,986
 1,929
Deferred income taxes(1,531) (169) 202
Amortization included in interest expense2
 (20) (36)
Inventory valuation adjustments—
 —
 (58)
Unit-based compensation expense74
 80
 79
Impairment losses920
 813
 339
Gains on acquisitions—
 (83) —
Losses on extinguishments of debt42
 —
 43
Impairment of investments in unconsolidated affiliates313
 308
 —
Distributions on unvested awards(31) (25) (16)
Equity in earnings of unconsolidated affiliates(156) (59) (469)
Distributions from unconsolidated affiliates440
 406
 440
Other non-cash(261) (271) (22)
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations(160) (246) (1,173)
Net cash provided by operating activities4,485
 3,303
 2,747
INVESTING ACTIVITIES:     
Cash proceeds from sale of Bakken Pipeline interest2,000
 —
 —
Cash proceeds from sale of Rover Pipeline interest1,478
 —
 —
Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction—
 2,200
 —
Proceeds from Bakken Pipeline Transaction—
 —
 980
Proceeds from Susser Exchange Transaction—
 —
 967
Proceeds from sale of noncontrolling interest—
 —
 64
Cash paid for acquisition of PennTex noncontrolling interest(280) —
 —
Cash paid for Vitol Acquisition, net of cash received—
 (769) —
Cash paid for PennTex Acquisition, net of cash received—
 (299) —
Cash transferred to ETE in connection with the Sunoco LP Exchange—
 —
 (114)
Cash paid for acquisition of a noncontrolling interest—
 —
 (129)
Cash paid for all other acquisitions(264) (159) (675)
Capital expenditures, excluding allowance for equity funds used during construction(8,335) (7,550) (9,098)
Contributions in aid of construction costs24
 71
 80
Contributions to unconsolidated affiliates(268) (59) (45)
Distributions from unconsolidated affiliates in excess of cumulative earnings136
 135
 124
Proceeds from the sale of assets35
 25
 23
Change in restricted cash—
 14
 19
Other1
 1
 (16)
Net cash used in investing activities(5,473) (6,390) (7,820)
      

FINANCING ACTIVITIES:     
Proceeds from borrowings26,736
 19,916
 22,462
Repayments of long-term debt(26,494) (15,799) (17,843)
Cash (paid to) received from affiliate notes(255) 124
 233
Common Units issued for cash2,283
 1,098
 1,428
Preferred Units issued for cash1,479
 —
 —
Subsidiary units issued for cash—
 1,388
 1,519
Predecessor units issued for cash—
 —
 34
Capital contributions from noncontrolling interest1,214
 236
 841
Distributions to partners(3,468) (3,542) (3,134)
Predecessor distributions to partners—
 —
 (202)
Distributions to noncontrolling interest(430) (481) (338)
Redemption of Legacy ETP Preferred Units(53) —
 —
Debt issuance costs(83) (22) (63)
Other5
 2
 —
Net cash provided by financing activities934
 2,920
 4,937
Decrease in cash and cash equivalents(54) (167) (136)
Cash and cash equivalents, beginning of period360
 527
 663
Cash and cash equivalents, end of period$306
 $360
 $527
* As adjusted. See Note 2.




ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)

1.OPERATIONS AND BASIS OF PRESENTATION:
Organization. The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETP”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner.
In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled.
In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein:
References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger;
References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and
References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger.
The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes).
The Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales.
The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia.
The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.

The Partnership owns a controlling interest in Sunoco Logistics Partners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLs and refined products.
Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the date the financial statements were issued.
For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity.
The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, these undivided interests are consolidated proportionately.
2.ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Change in Accounting Policy
During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.

As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows:
 Year Ended December 31, 2016 Year Ended December 31, 2015
 As Originally Reported* Effect of Change As Adjusted As Originally Reported* Effect of Change As Adjusted
Consolidated Statement of Operations and Comprehensive Income:           
Cost of products sold$15,039
 $41
 $15,080
 $26,682
 $32
 $26,714
Operating income1,802
 (41) 1,761
 2,259
 (32) 2,227
Income before income tax benefit438
 (41) 397
 1,398
 (32) 1,366
Net income624
 (41) 583
 1,521
 (32) 1,489
Net income attributable to partners297
 (9) 288
 1,398
 (9) 1,389
Net loss per common unit - basic(1.37) (0.01) (1.38) (0.06) (0.01) (0.07)
Net loss per common unit - diluted(1.37) (0.01) (1.38) (0.07) (0.01) (0.08)
Comprehensive income628
 (41) 587
 1,581
 (32) 1,549
Comprehensive income attributable to partners301
 (9) 292
 1,458
 (9) 1,449
            
Consolidated Statements of Cash Flows:           
Net income624
 (41) 583
 1,521
 (32) 1,489
Net change in operating assets and liabilities (change in inventories)(117) (129) (246) (1,367) 194
 (1,173)
            
Consolidated Balance Sheets (at period end):           
Inventories1,712
 (86) 1,626
 1,213
 (45) 1,168
Total partners' capital18,642
 (21) 18,621
 20,836
 (12) 20,824
* Amounts reflect certain reclassifications made to conform to the current year presentation.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Recent Accounting Pronouncements
ASU 2014-09
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.

The Partnership adopted ASU 2014-09 on January 1, 2018. The Partnership applied the cumulative catchup transition method and recognized the cumulative effect of the retrospective application of the standard. The effect of the retrospective application of the standard was not material.
For future periods, we expect that the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the designation of certain of our midstream segment agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the accounting for noncash consideration in multiple of our reportable segments, as well as fuel usage and loss allowances. None of these changes is expected to have a material impact on net income.
ASU 2016-02
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 in the first quarter of 2019 and is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
ASU 2016-16
On January 1, 2018, the Partnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. We do not anticipate a material impact to our financial position or results of operations as a result of the adoption of this standard.
ASU 2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance did not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017.
ASU 2017-12
In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures.
Revenue Recognition
Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available.
Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the

pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices.
Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead.
In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.
Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and segment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices.
We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer.
In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.
Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.

Regulatory Accounting – Regulatory Assets and Liabilities
Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations.  Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows:
 Years Ended December 31,
 2017 2016 2015
Accounts receivable$(950) $(919) $819
Accounts receivable from related companies67
 30
 (243)
Inventories37
 (497) (157)
Other current assets39
 83
 (178)
Other non-current assets, net(94) (78) 188
Accounts payable758
 972
 (1,215)
Accounts payable to related companies(3) 29
 (160)
Accrued and other current liabilities(47) 39
 (83)
Other non-current liabilities24
 33
 (219)
Price risk management assets and liabilities, net9
 62
 75
Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations$(160) $(246) $(1,173)

Non-cash investing and financing activities and supplemental cash flow information are as follows:
 Years Ended December 31,
 2017 2016 2015
NON-CASH INVESTING ACTIVITIES:     
Accrued capital expenditures$1,059
 $822
 $896
Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP—
 194
 —
Net gains from subsidiary common unit transactions—
 37
 300
NON-CASH FINANCING ACTIVITIES:     
Issuance of Common Units in connection with the PennTex Acquisition$—
 $307
 $—
Issuance of Common Units in connection with the Regency Merger—
 —
 9,250
Issuance of Class H Units in connection with the Bakken Pipeline Transaction—
 —
 1,946
Contribution of assets from noncontrolling interest988
 —
 34
Redemption of Common Units in connection with the Bakken Pipeline Transaction—
 —
 999
Redemption of Common Units in connection with the Sunoco LP Exchange—
 —
 52
SUPPLEMENTAL CASH FLOW INFORMATION:     
Cash paid for interest, net of interest capitalized$1,329
 $1,411
 $1,467
Cash paid for (refund of) income taxes50
 (229) 71
Accounts Receivable
Our operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty.
We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due.
We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets.
Inventories
As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017.
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower of cost or net realizable value utilizing the weighted-average cost method.

Inventories consisted of the following:
 December 31,
 2017 2016
Natural gas, NGLs, and refined products$733
 $758
Crude oil551
 651
Spare parts and other305
 217
Total inventories$1,589
 $1,626
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Other Current Assets
Other current assets consisted of the following:
 December 31,
 2017 2016
Deposits paid to vendors$64
 $74
Prepaid expenses and other146
 224
Total other current assets$210
 $298
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations.
Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value.
In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.

Components and useful lives of property, plant and equipment were as follows:
 December 31,
 2017 2016
Land and improvements$1,706
 $676
Buildings and improvements (1 to 45 years)1,960
 1,617
Pipelines and equipment (5 to 83 years)44,050
 36,356
Natural gas and NGL storage facilities (5 to 46 years)1,681
 1,452
Bulk storage, equipment and facilities (2 to 83 years)3,036
 3,701
Vehicles (1 to 25 years)124
 217
Right of way (20 to 83 years)3,424
 3,349
Natural resources434
 434
Other (1 to 40 years)534
 484
Construction work-in-process10,750
 9,934
 67,699
 58,220
Less – Accumulated depreciation and depletion(9,262) (7,303)
Property, plant and equipment, net$58,437
 $50,917
We recognized the following amounts for the periods presented:
 Years Ended December 31,
 2017 2016 2015
Depreciation and depletion expense$2,060
 $1,793
 $1,713
Capitalized interest283
 199
 163
Advances to and Investments in Unconsolidated Affiliates
We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
 December 31,
 2017 2016
Regulatory assets$85
 $86
Deferred charges210
 217
Restricted funds192
 190
Long-term affiliated receivable85
 90
Other186
 89
Total other non-current assets, net$758
 $672
(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities.
Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.

Intangible Assets
Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
Components and useful lives of intangible assets were as follows:
 December 31, 2017 December 31, 2016
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
Amortizable intangible assets:       
Customer relationships, contracts and agreements (3 to 46 years)$6,250
 $(1,003) $5,362
 $(737)
Patents (10 years)48
 (26) 48
 (21)
Trade Names (20 years)66
 (25) 66
 (22)
Other (5 to 20 years)1
 —
 2
 (2)
Total intangible assets$6,365
 $(1,054) $5,478
 $(782)
Aggregate amortization expense of intangible assets was as follows:
 Years Ended December 31,
 2017 2016 2015
Reported in depreciation, depletion and amortization$272
 $193
 $216
Estimated aggregate amortization expense for the next five years is as follows:
Years Ending December 31: 
2018$280
2019278
2020278
2021268
2022256
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate.
In 2015, we recorded $24 million of intangible asset impairments related to the NGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.

Changes in the carrying amount of goodwill were as follows:
 Intrastate
Transportation
and Storage		 Interstate
Transportation and Storage		 Midstream NGL and Refined Products Transportation and Services Crude Oil Transportation and Services All Other Total
Balance, December 31, 2015$10
 $912
 $718
 $772
 $912
 $2,104
 $5,428
Reduction due to contribution of legacy Sunoco, Inc. retail business—
 —
 —
 —
 —
 (1,289) (1,289)
Acquired—
 —
 177
 —
 251
 —
 428
Impaired—
 (638) (32) —
 —
 —
 (670)
Balance, December 31, 201610
 274
 863
 772
 1,163
 815
 3,897
Acquired—
 —
 8
 —
 4
 —
 12
Impaired—
 (262) —
 (79) —
 (452) (793)
Other—
 —
 (1) —
 —
 —
 (1)
Balance, December 31, 2017$10
 $12
 $870
 $693
 $1,167
 $363
 $3,115
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized.
During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded.
During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve.
During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $99 million in the interstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due to market declines in current and expected future commodity prices in the fourth quarter of 2015.
The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted

risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates.
Except for certain amounts discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 2017 and 2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. We believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time.
As of December 31, 2017 and 2016, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $165 million and $170 million, respectively.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future.  We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely.
Long-lived assets related to AROs aggregated $2 million and $14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 2017 and 2016, respectively. In addition, the Partnership had $21 million and $13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 2017 and 2016, respectively.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
 December 31,
 2017 2016
Interest payable$443
 $440
Customer advances and deposits59
 56
Accrued capital expenditures1,006
 749
Accrued wages and benefits208
 212
Taxes payable other than income taxes108
 63
Exchanges payable154
 208
Other165
 177
Total accrued and other current liabilities$2,143
 $1,905
Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.

Redeemable Noncontrolling Interests
The noncontrolling interest holders in one of our consolidated subsidiaries has the option to sell its interests to us.  In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheet.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 2017 was $34.28 billion and $33.09 billion, respectively. As of December 31, 2016, the aggregate fair value and carrying amount of our debt obligations was $33.85 billion and $32.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2017, no transfers were made between any levels within the fair value hierarchy.

The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 2017 and 2016 based on inputs used to derive their fair values:
 Fair Value Total Fair Value Measurements at December 31, 2017
 Level 1 Level 2
Assets:     
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX$11
 $11
 $—
Swing Swaps IFERC13
 —
 13
Fixed Swaps/Futures70
 70
 —
Forward Physical Swaps8
 —
 8
Power:     
Forwards23
 —
 23
Natural Gas Liquids – Forwards/Swaps193
 193
 —
Crude – Futures2
 2
 —
Total commodity derivatives320
 276
 44
Other non-current assets21
 14
 7
Total assets$341
 $290
 $51
Liabilities:     
Interest rate derivatives$(219) $—
 $(219)
Commodity derivatives:     
Natural Gas:     
Basis Swaps IFERC/NYMEX(24) (24) —
Swing Swaps IFERC(15) (1) (14)
Fixed Swaps/Futures(57) (57) —
Forward Physical Swaps(2) —
 (2)
Power – Forwards(22) —
 (22)
Natural Gas Liquids – Forwards/Swaps(192) (192) —
Refined Products – Futures(25) (25) —
Crude – Futures(1) (1) —
Total commodity derivatives(338) (300) (38)
Total liabilities$(557) $(300) $(257)

 Fair Value Total Fair Value Measurements at December 31, 2016
 Level 1 Level 2 Level 3
Assets:       
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX$14
 $14
 $—
 $—
Swing Swaps IFERC2
 —
 2
 —
Fixed Swaps/Futures96
 96
 —
 —
Forward Physical Swaps1
 —
 1
 —
Power:       
Forwards4
 —
 4
 —
Futures1
 1
 —
 —
Options – Calls1
 1
 —
 —
Natural Gas Liquids – Forwards/Swaps233
 233
 —
 —
Refined Products – Futures1
 1
 —
 —
Crude – Futures9
 9
 —
 —
Total commodity derivatives362
 355
 7
 —
Other non-current assets13
 8
 5
 —
Total assets$375
 $363
 $12
 $—
Liabilities:       
Interest rate derivatives$(193) $—
 $(193) $—
Embedded derivatives in the Legacy ETP Preferred Units(1) —
 —
 (1)
Commodity derivatives:       
Natural Gas:       
Basis Swaps IFERC/NYMEX(11) (11) —
 —
Swing Swaps IFERC(3) —
 (3) —
Fixed Swaps/Futures(149) (149) —
 —
Power:       
Forwards(5) —
 (5) —
Futures(1) (1) —
 —
Natural Gas Liquids – Forwards/Swaps(273) (273) —
 —
Refined Products – Futures(17) (17) —
 —
Crude – Futures(13) (13) —
 —
Total commodity derivatives(472) (464) (8) —
Total liabilities$(666) $(464) $(201) $(1)
Contributions in Aid of Construction Costs
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized.
Shipping and Handling Costs
Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.

Costs and Expenses
Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We record the collection of taxes to be remitted to government authorities on a net basis except for our all other segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). For the year ended December 31, 2015, excise taxes collected by Sunoco LP were $1.85 billion. The Partnership deconsolidated Sunoco LP effective July 1, 2015 and no excise taxes were collected by our consolidated operations subsequent to that date.
Issuances of Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital.
Income Taxes
ETP is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”).
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, and 2015, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company and until July 31, 2015, Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.

At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations.
We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations.
Unit-Based Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans).  Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability.  Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income
For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for United States Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.


3.ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
2018 Transactions
CDM Contribution Agreement
In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, payspursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions.
In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million.
2017 Transactions
Rover Contribution Agreement
In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments.
ETP and Sunoco Logistics Merger
As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger.
Permian Express Partners
In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.
In July 2017, ETP contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.

Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
2016 Transactions
PennTex Acquisition
On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, the Partnership purchased PennTex’s remaining outstanding common units in June 2017.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The total purchase price was allocated as follows:
  At November 1, 2016
Total current assets $34
Property, plant and equipment 393
Goodwill(1)
 177
Intangible assets 446
  1,050
   
Total current liabilities 6
Long-term debt, less current maturities 164
Other non-current liabilities 17
Noncontrolling interest 236
  423
Total consideration 627
Cash received 21
Total consideration, net of cash received $606
(1)
None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Sunoco Logistics’ Vitol Acquisition
In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC (“SunVit”), which increased Sunoco Logistics’ overall ownership of SunVit to 100%. The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million.

Bakken Financing
In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billion credit facility provided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2017, $2.50 billion was outstanding under this credit facility.
Bayou Bridge
In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system.
Sunoco Retail to Sunoco LP
In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of $1.29 billion and intangible assets of $294 million. The results of Sunoco, LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.
Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated:
 Year Ended December 31, 2015
Revenues$12,482
Cost of products sold11,174
Operating expenses798
Selling, general and administrative expenses106
2015 Transactions
Sunoco LP
In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million in Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015.
In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 31.5 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE provided ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. In connection with this transaction, the Partnership deconsolidated Sunoco LP, including goodwill of $1.81 billion and intangible assets of $982 million related to Sunoco LP. At December 31, 2017, the Partnership held 37.8 million Sunoco LP common units accounted for under the equity method. Subsequent to Sunoco LP’s

repurchase of a portion of its common units on February 7, 2018, as discussed in Note 4, our investment in Sunoco LP consists of 26.2 million units. The results of Sunoco LP’s operations have not been presented as discontinued operations and Sunoco LP’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements.
Bakken Pipeline
In March 2015, ETE transferred 46.2 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 Class I Units that provided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017.
In October 2015, Sunoco Logistics completed the acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access and ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction.
Regency Merger
On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.6186 Partnership common units. ETP issued 258.3 million Partnership common units to Regency unitholders, including 23.3 million units issued to Partnership subsidiaries. Regency’s 1.9 million outstanding Series A Convertible Preferred Units were converted into corresponding Legacy ETP Preferred Units on a one-for-one basis.
In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years.
The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger.
ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor.

4.ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
Citrus
ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, an approximately 5,360-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment.
FEP
We have a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. The Partnership recorded an impairment of its investment

in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor.
MEP
We own a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016.
HPC
We own a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Our investment in HPC is reflected in the intrastate transportation and storage segment. The Partnership evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, the Partnership recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes.
Sunoco LP
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from the Partnership. As a result, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. As of December 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units, and is reflected in the all other segment.
In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility.
The carrying values of the Partnership’s advances to and investments in unconsolidated affiliates as of December 31, 2017 and 2016 were as follows:
 December 31,
 2017 2016
Citrus$1,754
 $1,729
FEP121
 101
MEP242
 318
HPC28
 382
Sunoco LP1,095
 1,225
Others576
 525
Total$3,816
 $4,280

The following table presents equity in earnings (losses) of unconsolidated affiliates:
 Years Ended December 31,
 2017 2016 2015
Citrus$144
 $102
 $97
FEP53
 51
 55
MEP38
 40
 45
HPC(1)
(168) 31
 32
Sunoco, LLC—
 —
 (10)
Sunoco LP(2)
12
 (211) 202
Other77
 46
 48
Total equity in earnings of unconsolidated affiliates156
 59
 469
(1)
For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
(2)
For the years ended December 31, 2017 and 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million, respectively.
Summarized Financial Information
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, FEP, MEP, HPC and Sunoco LP (on a 100% basis) for all periods presented:
 December 31,
 2017 2016
Current assets$4,750
 $1,532
Property, plant and equipment, net9,893
 10,310
Other assets2,286
 5,980
Total assets$16,929
 $17,822
    
Current liabilities$2,075
 $1,918
Non-current liabilities9,375
 10,343
Equity5,479
 5,561
Total liabilities and equity$16,929
 $17,822
 Years Ended December 31,
 2017 2016 2015
Revenue$13,081
 $11,150
 $13,815
Operating income636
 859
 1,052
Net income (loss)294
 (22) 664
In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.


5.NET INCOME (LOSS) PER LIMITED PARTNER UNIT:
The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit.
The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
 Years Ended December 31,
 2017 2016 2015
Net income$2,501
 $583
 $1,489
Less: Income attributable to noncontrolling interest420
 295
 134
Less: Loss attributable to predecessor—
 —
 (34)
Net income, net of noncontrolling interest2,081
 288
 1,389
General Partner’s interest in net income990
 948
 1,064
Preferred Unitholders’ interest in net income12
 —
 —
Class H Unitholder’s interest in net income93
 351
 258
Class I Unitholder’s interest in net income—
 8
 94
Common Unitholders’ interest in net income (loss)986
 (1,019) (27)
Additional earnings allocated from (to) General Partner9
 (10) (5)
Distributions on employee unit awards, net of allocation to General Partner(27) (19) (16)
Net income (loss) available to Common Unitholders$968
 $(1,048) $(48)
Weighted average Common Units – basic1,032.7
 758.2
 649.2
Basic net income (loss) per Common Unit$0.94
 $(1.38) $(0.07)
      
Income (loss) available to Common Unitholders$968
 $(1,048) $(48)
Loss attributable to Legacy ETP Preferred Units—
 —
 (6)
Diluted income (loss) available to Common Unitholders$968
 $(1,048) $(54)
Weighted average Common Units – basic1,032.7
 758.2
 649.2
Dilutive effect of unvested Unit Awards5.1
 —
 —
Dilutive effect of Legacy ETP Preferred Units—
 —
 1.0
Weighted average Common Units – diluted1,037.8
 758.2
 650.2
Diluted income (loss) per Common Unit$0.93
 $(1.38) $(0.08)

6.DEBT OBLIGATIONS:
Our debt obligations consist of the following:
 December 31,
 2017 2016
ETP Debt   
6.125% Senior Notes due February 15, 2017$—
 $400
2.50% Senior Notes due June 15, 2018 (1)650
 650
6.70% Senior Notes due July 1, 2018 (1)600
 600
9.70% Senior Notes due March 15, 2019400
 400
9.00% Senior Notes due April 15, 2019450
 450
5.50% Senior Notes due February 15, 2020250
 250
5.75% Senior Notes due September 1, 2020400
 400

4.15% Senior Notes due October 1, 20201,050
 1,050
4.40% Senior Notes due April 1, 2021600
 600
6.50% Senior Notes due July 15, 2021—
 500
4.65% Senior Notes due June 1, 2021800
 800
5.20% Senior Notes due February 1, 20221,000
 1,000
4.65% Senior Notes due February 15, 2022300
 300
5.875% Senior Notes due March 1, 2022900
 900
5.00% Senior Notes due October 1, 2022700
 700
3.45% Senior Notes due January 15, 2023350
 350
3.60% Senior Notes due February 1, 2023800
 800
5.50% Senior Notes due April 15, 2023—
 700
4.50% Senior Notes due November 1, 2023600
 600
4.90% Senior Notes due February 1, 2024350
 350
7.60% Senior Notes due February 1, 2024277
 277
4.25% Senior Notes due April 1, 2024500
 500
9.00% Debentures due November 1, 202465
 65
4.05% Senior Notes due March 15, 20251,000
 1,000
5.95% Senior Notes due December 1, 2025400
 400
4.75% Senior Notes due January 15, 20261,000
 1,000
3.90% Senior Notes due July 15, 2026550
 550
4.20% Senior Notes due April 15, 2027600
 —
4.00% Senior Notes due October 1, 2027750
 —
8.25% Senior Notes due November 15, 2029267
 267
4.90% Senior Notes due March 15, 2035500
 500
6.625% Senior Notes due October 15, 2036400
 400
7.50% Senior Notes due July 1, 2038550
 550
6.85% Senior Notes due February 15, 2040250
 250
6.05% Senior Notes due June 1, 2041700
 700
6.50% Senior Notes due February 1, 20421,000
 1,000
6.10% Senior Notes due February 15, 2042300
 300
4.95% Senior Notes due January 15, 2043350
 350
5.15% Senior Notes due February 1, 2043450
 450
5.95% Senior Notes due October 1, 2043450
 450
5.30% Senior Notes due April 1, 2044700
 700
5.15% Senior Notes due March 15, 20451,000
 1,000
5.35% Senior Notes due May 15, 2045800
 800
6.125% Senior Notes due December 15, 20451,000
 1,000
5.30% Senior Notes due April 15, 2047900
 —
5.40% Senior Notes due October 1, 20471,500
 —
Floating Rate Junior Subordinated Notes due November 1, 2066546
 546
ETP $4.0 billion Revolving Credit Facility due December 20222,292
 —
ETP $1.0 billion 364-Day Credit Facility due November 2018 (2)50
 —
ETLP $3.75 billion Revolving Credit Facility due November 2019—
 2,777
Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020—
 1,292
Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017—
 630
Unamortized premiums, discounts and fair value adjustments, net33
 66
Deferred debt issuance costs(170) (166)
 29,210
 29,454
Transwestern Debt   
5.64% Senior Notes due May 24, 2017—
 82
5.36% Senior Notes due December 9, 2020175
 175
5.89% Senior Notes due May 24, 2022150
 150
5.66% Senior Notes due December 9, 2024175
 175
6.16% Senior Notes due May 24, 203775
 75
Deferred debt issuance costs(1) (1)
 574
 656
Panhandle Debt   
6.20% Senior Notes due November 1, 2017—
 300

7.00% Senior Notes due June 15, 2018400
 400
8.125% Senior Notes due June 1, 2019150
 150
7.60% Senior Notes due February 1, 202482
 82
7.00% Senior Notes due July 15, 202966
 66
8.25% Senior Notes due November 15, 202933
 33
Floating Rate Junior Subordinated Notes due November 1, 206654
 54
Unamortized premiums, discounts and fair value adjustments, net28
 50
 813
 1,135
Sunoco, Inc. Debt   
5.75% Senior Notes due January 15, 2017—
 400
    
Bakken Project Debt   
Bakken Project $2.50 billion Credit Facility due August 20192,500
 1,100
Deferred debt issuance costs(8) (13)
 2,492
 1,087
PennTex Debt   
PennTex $275 million Revolving Credit Facility due December 2019—
 168
    
Other5
 30
 33,094
 32,930
Less: Current maturities of long-term debt407
 1,189
 $32,687
 $31,741
(1)
As of December 31, 2017 management had the intent and ability to refinance the $650 million 2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current.
(2)
Borrowings under 364-day credit facilities were classified as long-term debt based on the Partnership’s ability and intent to refinance such borrowings on a long-term basis.
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs:
2018 $1,700
2019 3,500
2020 1,875
2021 1,400
2022 5,346
Thereafter 19,391
Total $33,212
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
ETP Senior Notes
The ETP senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually.
The ETP senior notes are unsecured obligations of the Partnership and as a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.

Transwestern Senior Notes
The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017.
Credit Facilities and Commercial Paper
ETP Credit Facilities
On December 1, 2017 the Partnership entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”).  The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to $6.0 billion under certain conditions. We use the ETP Credit Facilities to provide temporary financing for our growth projects, as well as for general partnership purposes.
As of December 31, 2017, the ETP Five-Year Facility had $2.29 billion outstanding, of which $2.01 billion was commercial paper. The amount available for future borrowings was $1.56 billion after taking into account letters of credit of $150 million. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 2.48%.
As of December 31, 2017, the ETP 364-Day Facility had $50 million outstanding, and the amount available for future borrowings was $950 million. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 5.00%.
ETLP Credit Facility
The ETLP Credit Facility allowed for borrowings of up to $3.75 billion and was used to provide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.
Sunoco Logistics Credit Facilities
ETP maintained a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017.
In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility (“364-Day Credit Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility was terminated and repaid in May 2017.
Bakken Credit Facility
In August 2016, Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 completed project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2017, the Bakken Credit Facility had $2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 3.00%.
PennTex Revolving Credit Facility
PennTex previously maintained a $275 million revolving credit commitment (the “PennTex Revolving Credit Facility”). In August 2017, the PennTex Revolving Credit Facility was repaid and terminated.

Covenants Related to Our Credit Agreements
Covenants Related to ETP
The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The ETP Credit Facilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things:
incur indebtedness;
grant liens;
enter into mergers;
dispose of assets;
make certain investments;
make Distributions (as defined in the ETP Credit Facilities) during certain Defaults (as defined in the ETP Credit Facilities) and during any Event of Default (as defined in the ETP Credit Facilities);
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
engage in transactions with affiliates; and
enter into restrictive agreements.
The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from 0.125% to 0.300%.  The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225%.
The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit Facilities also limit us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreements, of 5.0 to 1, which can generally be increased to 5.5 to 1 during a Specified Acquisition Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as calculated in accordance with the credit agreements.
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions.
Covenants Related to Panhandle
Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants.
Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-

acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries.
In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt.
Covenants Related to Bakken Credit Facility
The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to:
prohibition of certain incremental secured indebtedness;
prohibition of certain liens / negative pledge;
limitations on uses of loan proceeds;
limitations on asset sales and purchases;
limitations on permitted business activities;
limitations on mergers and acquisitions;
limitations on investments;
limitations on transactions with affiliates; and
maintenance of commercially reasonable insurance coverage.
A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.
Compliance with our Covenants
We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2017.

7.LEGACY ETP PREFERRED UNITS:
The Legacy ETP Preferred Units were mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and were reflected as long-term liabilities in our consolidated balance sheets. The Legacy ETP Preferred Units were entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record dates of the Partnership’s common unit distributions. In January 2017, ETP repurchased all of its 1.9 million outstanding Legacy ETP Preferred Units for cash in the aggregate amount of $53 million.

8.EQUITY:
Limited Partner interests are represented by Common, Class E Units, Class G Units, Class I Units, Class J Units and Class K Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s outstanding securities also include preferred units, as described below. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance.

IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs.
Common Units
The change in Common Units was as follows:
 Years Ended December 31,
 
2017 (1)
 
2016 (1)
 
2015 (1)
Number of Common Units, beginning of period794.8
 758.5
 533.4
Common Units redeemed in connection with certain transactions—
 (26.7) (77.8)
Common Units issued in connection with public offerings54.0
 —
 —
Common Units issued in connection with certain acquisitions—
 13.3
 258.2
Common Units issued in connection with the Distribution Reinvestment Plan12.0
 9.9
 11.7
Common Units issued in connection with Equity Distribution Agreements22.6
 39.0
 31.7
Common Units issued to ETE in a private placement transaction23.7
 —
 —
Common Unit increase from Sunoco Logistics Merger (2)255.4
 —
 —
Issuance of Common Units under equity incentive plans1.6
 0.8
 1.3
Number of Common Units, end of period1,164.1
 794.8
 758.5
(1)
The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger.
(2)
Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger.
Our Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”
Equity Distribution Program
From time to time, we have sold Common Units through equity distribution agreements. Such sales of Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreements.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.00 billion.
During the year ended December 31, 2017, we issued 22.6 million units for $503 million, net of commissions of $5 million. As of December 31, 2017, $752 million of our Common Units remained available to be issued under our currently effective equity distribution agreement.
Equity Incentive Plan Activity
We issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.

Distribution Reinvestment Program
Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units.
In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, the Partnership initiated a new distribution reinvestment plan.
During the years ended December 31, 2017, 2016 and 2015, aggregate distributions of $228 million, $216 million, and $360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 25.5 million Common Units.
As of December 31, 2017, a total of 20.8 million Common Units remain available to be issued under the existing registration statement.
August 2017 Units Offering
In August 2017, the Partnership issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by the Partnership to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes.
January 2017 Private Placement
In January 2017, the Partnership sold 23.7 million ETP Common Units to ETE in a private placement transaction for gross proceeds of approximately $568 million.
Class E Units
There are currently 8.9 million Class E Units outstanding, all of which are currently owned by HHI. The Class E Units generally do not have any voting rights. The Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year. As the Class E Units are owned by a wholly-owned subsidiary, the cash distributions on those units are eliminated in our consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire the Class E Units at a future date.
Class G Units
There are currently 90.7 million Class G Units outstanding, all of which are held by a wholly-owned subsidiary of the Partnership. The Class G Units generally do not have any voting rights. The Class G Units are entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class G Unit per year. Allocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are reflected as treasury units in the consolidated financial statements.
Class H Units
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which were generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. The Class H units were cancelled in connection with the merger of ETP and Sunoco Logistics in April 2017.
Class I Units
In connection with the Bakken Pipeline Transaction discussed in Note 3, in April 2015, ETP issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the

cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter ended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding.
Bakken Equity Sale
In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction.
Class K Units
On December 29, 2016, the Partnership issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in the Partnership, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco.  If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2017, a total of 101.5 million Class K Units were held by wholly-owned subsidiaries of ETP.
Sales of Common Units by legacy Sunoco Logistics
Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol.
In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes.
In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the Sunoco Logistics Merger, the previous Sunoco Logistics equity distribution agreement was terminated.
ETP Preferred Units
In November 2017, ETP issued 950,000 of its 6.250% Series A Preferred Units at a price of $1,000 per unit, and 550,000 of its 6.625% Series B Preferred Units at a price of $1,000 per unit.
Distributions on the Series A Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation

preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
PennTex Tender Offer and Limited Call Right Exercise
In June 2017, ETP purchased all of the outstanding PennTex common units not previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.
Quarterly Distributions of Available Cash
Under the Partnership’s limited partnership agreement, within 45 days after the end of each quarter, the Partnership distributes all cash on hand at the end of the quarter, less reserves established by the general partner in its discretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct the Partnership’s business. The Partnership will make quarterly distributions to the extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”
The following table shows the target distribution levels and distribution “splits” between the general and limited partners and the holders of the Partnership’s incentive distribution rights (”IDRs”):
    Marginal Percentage Interest in Distributions
  Total Quarterly Distribution Target Amount IDRs 
Partners (1)
Minimum Quarterly Distribution $0.0750 —% 100%
First Target Distribution up to $0.0833 —% 100%
Second Target Distribution above $0.0833 up to $0.0958 13% 87%
Third Target Distribution above $0.0958 up to $0.2638 35% 65%
Thereafter above $0.2638 48% 52%
(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows:
Quarter Ended ETP Sunoco Logistics
December 31, 2014 $0.6633
 $0.4000
March 31, 2015 0.6767
 0.4190
June 30, 2015 0.6900
 0.4380
September 30, 2015 0.7033
 0.4580
December 31, 2015 0.7033
 0.4790
March 31, 2016 0.7033
 0.4890
June 30, 2016 0.7033
 0.5000
September 30, 2016 0.7033
 0.5100
December 31, 2016 0.7033
 0.5200

Distributions on common units declared and paid by Post-Merger ETP were as follows:
Quarter Ended Record Date Payment Date Rate
March 31, 2017 May 10, 2017 May 16, 2017 $0.5350
June 30, 2017 August 7, 2017 August 15, 2017 0.5500
September 30, 2017 November 7, 2017 November 14, 2017 0.5650
December 31, 2017 February 8, 2018 February 14, 2018 0.5650
In connection with previous transactions, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods:
  Total Year
2018 $153
2019 128
Each year beyond 2019 33
Distributions declared and paid by ETP to the preferred unitholders were as follows:
 Distribution per Preferred Unit
Quarter Ended Record Date Payment Date Series A Series B
December 31, 2017 February 1, 2018 February 15, 2018 $15.451
 $16.378
Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
 December 31,
 2017 2016
Available-for-sale securities$8
 $2
Foreign currency translation adjustment(5) (5)
Actuarial gain related to pensions and other postretirement benefits(5) 7
Investments in unconsolidated affiliates, net5
 4
Total AOCI, net of tax$3
 $8
The table below sets forth the tax amounts included in the respective components of other comprehensive income:
 December 31,
 2017 2016
Available-for-sale securities$(2) $(2)
Foreign currency translation adjustment3
 3
Actuarial loss relating to pension and other postretirement benefits3
 —
Total$4
 $1

9.UNIT-BASED COMPENSATION PLANS:
ETP Unit-Based Compensation Plan
We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent

rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2017, an aggregate total of 8.4 million ETP Common Units remain available to be awarded under our equity incentive plans.
Restricted Units
We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement.
The following table shows the activity of the awards granted to employees and non-employee directors:
 Number of Units Weighted Average Grant-Date Fair Value Per Unit
Unvested awards as of December 31, 20169.4
 $27.68
Legacy Sunoco Logistics unvested awards as of December 31, 20163.2
 28.57
Awards granted4.9
 17.69
Awards vested(2.3) 34.22
Awards forfeited(1.1) 25.03
Unvested awards as of December 31, 201714.1
 23.18
During the years ended December 31, 2017, 2016, and 2015, the weighted average grant-date fair value per unit award granted was $17.69, $23.82 and $23.47, respectively. The total fair value of awards vested was $40 million, $40 million and $57 million, respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2017, a total of 14.1 million unit awards remain unvested, for which ETP expects to recognize a total of $189 million in compensation expense over a weighted average period of 2.7 years.
Cash Restricted Units. The Partnership previously granted cash restricted units, which entitled the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. The Partnership does not currently have any cash restricted units outstanding.

10.INCOME TAXES:
As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows:
 Years Ended December 31,
 2017 2016 2015
Current expense (benefit):     
Federal$53
 $18
 $(274)
State(18) (35) (51)
Total35
 (17) (325)
Deferred expense (benefit):     
Federal(1,723) (173) 231
State192
 4
 (29)
Total(1,531) (169) 202
Total income tax benefit$(1,496) $(186) $(123)

Historically, our effective rate has differed from the statutory rate primarily due to Partnership earnings that are not subject to United States federal and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s income tax benefit for the years ended December 31, 2017, 2016 and 2015 is as follows:
 Years Ended December 31,
 2017 2016* 2015*
Income tax expense at United States statutory rate of 35 percent$352
 $139
 $479
Increase (reduction) in income taxes resulting from:     
Partnership earnings not subject to tax(457) (504) (504)
Federal rate change(1,559) —

—
Goodwill impairments172
 223
 —
State income taxes (net of federal income tax effects)131
 (17) (37)
Dividend received deduction(14) (15) (24)
Audit settlement—
 —
 (7)
Change in tax status of subsidiary(124) —
 —
Other3
 (12) (30)
Income tax benefit$(1,496) $(186) $(123)
* As adjusted. See Note 2.
Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows:
 December 31,
 2017 2016
Deferred income tax assets:   
Net operating losses and alternative minimum tax credit$604
 $380
Pension and other postretirement benefits21
 30
Long-term debt14
 32
Other93
 84
Total deferred income tax assets732
 526
Valuation allowance(189) (118)
Net deferred income tax assets$543
 $408
    
Deferred income tax liabilities:   
Property, plant and equipment$(664) $(1,054)
Investment in unconsolidated affiliates(2,664) (3,728)
Other(98) (20)
Total deferred income tax liabilities(3,426) (4,802)
Net deferred income taxes$(2,883) $(4,394)

The table below provides a rollforward of the net deferred income tax liability as follows:
 December 31,
 2017 2016
Net deferred income tax liability, beginning of year$(4,394) $(4,082)
Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3)—
 (460)
Tax provision1,531
 169
Other(20) (21)
Net deferred income tax liability, end of year$(2,883) $(4,394)
ETP Holdco and other corporate subsidiaries have federal net operating loss carryforward of $1.57 billion, all of which will expire in 2031 through 2037. Our corporate subsidiaries have $62 million of federal alternative minimum tax credits at December 31, 2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have state net operating loss carryforward benefits of $210 million, net of federal tax, which expire between 2018 and 2036. A valuation allowance of $186 million is applicable to the state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.
The following table sets forth the changes in unrecognized tax benefits:
 Years Ended December 31,
 2017 2016 2015
Balance at beginning of year$615
 $610
 $440
Additions attributable to tax positions taken in the current year—
 8
 —
Additions attributable to tax positions taken in prior years28
 18
 178
Reduction attributable to tax positions taken in prior years(25) (20) —
Lapse of statute(9) (1) (8)
Balance at end of year$609
 $615
 $610
As of December 31, 2017, we have $605 million ($576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2017, we recognized interest and penalties of less than $3 million. At December 31, 2017, we have interest and penalties accrued of $9 million, net of tax.
Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in this litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 2017.
In December 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL limitation in its entirety.  In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact.  Nextel has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court.  Sunoco, Inc. has recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter.  However, based upon the Pennsylvania Supreme Court’s

October 2017 decision, and because of uncertainty in the breadth of the application of the decision, we have reserved $27 million ($21 million after federal income tax benefits) against the receivable.
In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007.
Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments.
ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations.
On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefit of $1.56 billion in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.

11.REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
Contingent Residual Support Agreement – AmeriGas
In connection with the closing of the contribution of its propane operations in January 2012, ETP previously provided contingent residual support of certain debt obligations of AmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and ETP no longer provides contingent residual support for any AmeriGas notes.
Guarantee of Sunoco LP Notes
In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC (“ETC M-A”).
On January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
$1.00 billion aggregate principal amount of 4.875%, senior notes due 2023;
$800 million aggregate principal amount of 5.50% senior notes due 2026; and
$400 million aggregate principal amount of 5.875% senior notes due 2028.
Under the guarantee of collection, ETC M-A would have the obligation to pay the principal of each series of notes once all remedies, including in the context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in respect of the principal of such notes. ETC M-A will not otherwise be subject to the covenants of the indenture governing the notes.
FERC Audit
In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing.
Commitments
In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP

believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations.
ETP’s joint venture agreements require that it funds its proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon ETP’s unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income:
  Years Ended December 31,
  2017 2016 2015
Rental expense(1)
 $90
 $81
 $176
Less: Sublease rental income —
 (1) (16)
Rental expense, net $90
 $80
 $160
(1)
Includes contingent rentals totaling $26 million for the year ended December 31, 2015.
Future minimum lease commitments for such leases are:
Years Ending December 31: 
2018$39
201936
202037
202130
202223
Thereafter92
Future minimum lease commitments257
Less: Sublease rental income(8)
Net future minimum lease commitments$249
Litigation and Contingencies
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
Dakota Access Pipeline
On July 25, 2016, the United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. After significant delay, the USACE also issued easements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. Also in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia against the USACE that challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access intervened in the case. The SRST soon added a

request for an emergency temporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction, rendering the TRO request moot.
After the September 9, 2016 ruling, the Department of the Army, the DOJ, and the Department of the Interior released a joint statement that the USACE would not grant the easement for the land adjacent to Lake Oahe until the Department of the Army completed a review to determine whether it was necessary to reconsider the USACE’s decision under various federal statutes relevant to the pipeline approval.
The SRST appealed the denial of the preliminary injunction to the United States Court of Appeals for the D.C. Circuit and filed an emergency motion in the United States District Court for an injunction pending the appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statutes governing the use of government property.
In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In February 2017, in response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access allowing the pipeline to cross Lake Oahe. Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened in the lawsuit in August 2016, moved for a preliminary injunction and TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the Tribe. The District Court denied the TRO and preliminary injunction, and the CRST appealed and requested an injunction pending appeal in the district court and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.
The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes.
On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018.
On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access is required to file the revised plan with the Court by April 1, 2018. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first report was filed with the court on December 29, 2017.
In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. Briefing on YST’s motion is ongoing.
While we believe that the pending lawsuits are unlikely to halt or suspend the operation of the pipeline, we cannot assure this outcome. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.

Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. Lone Star is still quantifying the extent of its incurred and ongoing damages and has or will be seeking reimbursement for these losses.
MTBE Litigation
Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other members of the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees.
As of December 31, 2017, Sunoco, Inc. is a defendant in seven cases, including one case each initiated by the States of Maryland, New Jersey, Vermont, Rhode Island, one by the Commonwealth of Pennsylvania and two by the Commonwealth of Puerto Rico. The more recent Puerto Rico action is a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are pending in a multidistrict litigation proceeding in a New York federal court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and one is pending in state court in Maryland.
Sunoco, Inc. and Sunoco, Inc. (R&M) have reached a settlement with the State of New Jersey. The Court approved the Judicial Consent Order on December 5, 2017. Dismissal of the case against Sunoco, Inc. and Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Regency Merger Litigation
Following the January 26, 2015 announcement of the Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, Dieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”).
The Regency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. On March 29, 2016, the Delaware Court of Chancery granted the Regency Litigation Defendants’ motion to dismiss the lawsuit in its entirety. Dieckman appealed. On January 20, 2017, the Delaware Supreme Court reversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC.
The Regency Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.

Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation
On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc.  Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP.  The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement.  On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest.  The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims.  Enterprise filed a notice of appeal with the Court of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and reversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP filed a petition for review with the Texas Supreme Court. Enterprise’s response is due February 26, 2018.
Sunoco Logistics Merger Litigation
Seven purported Energy Transfer Partners, L.P. common unitholders (the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits against ETP, ETP GP, ETP LLC, the members of the ETP Board, and ETE (the “ETP-SXL Defendants”) in connection with the announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits were consolidated as In re Energy Transfer Partners, L.P. Shareholder Litig., C.A. No. 1:17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Sunoco Logistics Merger Litigation”). The ETP Unitholder Plaintiffs allege causes of action challenging the merger and the proxy statement/prospectus filed in connection with the Sunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs sought rescission of the Sunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and attorneys’ fees. On October 5, 2017, the ETP-SXL Defendants filed a Motion to Dismiss the ETP Unitholder Plaintiffs’ claims. Rather than respond to the Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017.
The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of any such lawsuits might be. Nor can the ETP-SXL Defendants predict the amount of time and expense that would be required to resolve such lawsuits. The ETP-SXL Defendants believe the Sunoco Logistics Merger Litigation was without merit and intend to defend vigorously against any future lawsuits challenging the Sunoco Logistics Merger.
Litigation filed by BP Products
On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million.
SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016.
On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.
On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.

Other Litigation and Contingencies
We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 2017 and 2016, accruals of approximately $33 million and $77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued.
No amounts have been recorded in our December 31, 2017 or 2016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs.
In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality.
On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped.  The Administrative Order detailed alleged violations of the permits issued by PADEP in

February of 2017, during the construction of the project.  Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues.  Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018.  On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania.  In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP.  PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order.  That request was granted on February 8, 2018.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites.
Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2017, Sunoco, Inc. had been named as a PRP at approximately 43 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements.
 December 31,
 2017 2016
Current$36
 $26
Non-current314
 283
Total environmental liabilities$350
 $309
In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.

During the years ended December 31, 2017 and 2016, the Partnership recorded $23 million and $43 million, respectively, of expenditures related to environmental cleanup programs.
On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 to the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
Our pipeline operations are subject to regulation by the United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures.
In January 2012, we experienced a release on our products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which we are obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. This PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. We also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. We have also received a “No Further Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, we received a proposed penalty from the EPA and DOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, we do not expect there to be a material impact to our results of operations, cash flows or financial position.
In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to our West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. We do not expect there to be a material impact to our results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of our Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of $100,000. The case went to Hearing in November 2016 and remains open with PHMSA. We do not expect there to be a material impact to our results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. We do not expect there to be a material impact to our results of operations, cash flows, or financial position.
In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on our Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. We do not expect there to be a material impact to our results of operations, cash flows or financial position.
Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, Occupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for

OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.

12.DERIVATIVE ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.

The following table details our outstanding commodity-related derivatives:
 December 31, 2017 December 31, 2016
 
Notional
Volume
 Maturity 
Notional
Volume
 Maturity
Mark-to-Market Derivatives       
(Trading)       
Natural Gas (BBtu):       
Fixed Swaps/Futures1,078
 2018 (683) 2017
Basis Swaps IFERC/NYMEX(1)
48,510
 2018-2020 2,243
 2017
Options – Calls13,000
 2018 —
 —
Power (Megawatt):       
Forwards435,960
 2018-2019 391,880
 2017-2018
Futures(25,760) 2018 109,564
 2017-2018
Options – Puts(153,600) 2018 (50,400) 2017
Options – Calls137,600
 2018 186,400
 2017
Crude (MBbls) – Futures—
 — (617) 2017
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX4,650
 2018-2020 10,750
 2017-2018
Swing Swaps IFERC87,253
 2018-2019 (5,663) 2017
Fixed Swaps/Futures(4,700) 2018-2019 (52,653) 2017-2019
Forward Physical Contracts(145,105) 2018-2020 (22,492) 2017
Natural Gas Liquid (MBbls) – Forwards/Swaps6,679
 2018-2019 (5,787) 2017
Refined Products (MBbls) – Futures(3,783) 2018-2019 (2,240) 2017
Fair Value Hedging Derivatives       
(Non-Trading)       
Natural Gas (BBtu):       
Basis Swaps IFERC/NYMEX(39,770) 2018 (36,370) 2017
Fixed Swaps/Futures(39,770) 2018 (36,370) 2017
Hedged Item – Inventory39,770
 2018 36,370
 2017
(1)
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations.
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.

The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes:
Term 
Type(1)
 Notional Amount Outstanding
December 31, 2017 December 31, 2016
July 2017(2)
 Forward-starting to pay a fixed rate of 3.90% and receive a floating rate $—
 $500
July 2018(2)
 Forward-starting to pay a fixed rate of 3.76% and receive a floating rate 300
 200
July 2019(2)
 Forward-starting to pay a fixed rate of 3.64% and receive a floating rate 300
 200
July 2020(2)
 Forward-starting to pay a fixed rate of 3.52% and receive a floating rate 400
 —
December 2018 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% 1,200
 1,200
March 2019 Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% 300
 300
(1)
Floating rates are based on 3-month LIBOR.
(2)
Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date.
Credit Risk
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties.
The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.

Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
 Fair Value of Derivative Instruments
 Asset Derivatives Liability Derivatives
 December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives designated as hedging instruments:       
Commodity derivatives (margin deposits)$14
 $—
 $(2) $(4)
 14
 —
 (2) (4)
Derivatives not designated as hedging instruments:       
Commodity derivatives (margin deposits)262
 338
 (281) (416)
Commodity derivatives44
 24
 (55) (52)
Interest rate derivatives—
 —
 (219) (193)
Embedded derivatives in Legacy ETP Preferred Units—
 —
 —
 (1)
 306
 362
 (555) (662)
Total derivatives$320
 $362
 $(557) $(666)
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
    Asset Derivatives Liability Derivatives
  Balance Sheet Location December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016
Derivatives without offsetting agreements Derivative liabilities $—
 $—
 $(219) $(194)
Derivatives in offsetting agreements:        
OTC contracts Derivative assets (liabilities) 44
 24
 (55) (52)
Broker cleared derivative contracts Other current assets (liabilities) 276
 338
 (283) (420)
  320
 362
 (557) (666)
Offsetting agreements:        
Counterparty netting Derivative assets (liabilities) (20) (4) 20
 4
Counterparty netting Other current assets (liabilities) (263) (338) 263
 338
Total net derivatives $37
 $20
 $(274) $(324)
We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.

The following tables summarize the amounts recognized with respect to our derivative financial instruments:
 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness
   Years Ended December 31,
   2017 2016 2015
Derivatives in fair value hedging relationships (including hedged item):       
Commodity derivativesCost of products sold $26
 $14
 $21
Total  $26
 $14
 $21
 Location of Gain/(Loss) Recognized in Income on Derivatives Amount of Gain (Loss) Recognized in Income on Derivatives
   Years Ended December 31,
   2017 2016 2015
Derivatives not designated as hedging instruments:       
Commodity derivatives – TradingCost of products sold $31
 $(35) $(11)
Commodity derivatives – Non-tradingCost of products sold 3
 (173) 23
Interest rate derivativesLosses on interest rate derivatives (37) (12) (18)
Embedded derivativesOther, net 1
 4
 12
Total  $(2) $(216) $6

13.RETIREMENT BENEFITS:
Savings and Profit Sharing Plans
We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $38 million, $44 million and $39 million to these 401(k) savings plans for the years ended December 31, 2017, 2016, and 2015, respectively.
Pension and Other Postretirement Benefit Plans
Panhandle
Postretirement benefits expense for the years ended December 31, 2017, 2016 and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees.
Sunoco, Inc.
Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.

Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
Obligations and Funded Status
Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis:
 December 31, 2017 December 31, 2016
 Pension Benefits   Pension Benefits  
 Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Change in benefit obligation:           
Benefit obligation at beginning of period$18
 $51
 $165
 $20
 $57
 $180
Interest cost1
 1
 4
 1
 2
 4
Amendments—
 —
 7
 —
 —
 —
Benefits paid, net(2) (6) (20) (1) (7) (21)
Actuarial (gain) loss and other2
 1
 (1) (2) (1) 2
Settlements(18) —
 —
 —
 —
 —
Benefit obligation at end of period1
 47
 155
 18
 51
 165
            
Change in plan assets:           
Fair value of plan assets at beginning of period12
 —
 248
 15
 —
 253
Return on plan assets and other3
 —
 11
 (2) —
 6
Employer contributions6
 —
 10
 —
 —
 10
Benefits paid, net(2) —
 (20) (1) —
 (21)
Settlements(18) —
 —
 —
 —
 —
Fair value of plan assets at end of period1
 —
 249
 12
 —
 248
            
Amount underfunded (overfunded) at end of period$—
 $47
 $(94) $6
 $51
 $(83)
            
Amounts recognized in the consolidated balance sheets consist of:           
Non-current assets$—
 $—
 $120
 $—
 $—
 $108
Current liabilities—
 (8) (2) —
 (7) (2)
Non-current liabilities—
 (39) (24) (6) (44) (23)
 $—
 $(47) $94
 $(6) $(51) $83
            
Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of:           
Net actuarial gain$—
 $5
 $(17) $—
 $—
 $(12)
Prior service cost—
 —
 20
 —
 —
 14
 $—
 $5
 $3
 $—
 $—
 $2

The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
 December 31, 2017 December 31, 2016
 Pension Benefits   Pension Benefits  
 Funded Plans Unfunded Plans Other Postretirement Benefits Funded Plans Unfunded Plans Other Postretirement Benefits
Projected benefit obligation$1
 $47
 N/A
 $18
 $51
 N/A
Accumulated benefit obligation1
 47
 $155
 18
 51
 $165
Fair value of plan assets1
 —
 249
 12
 —
 248
Components of Net Periodic Benefit Cost
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Net periodic benefit cost:       
Interest cost$2
 $4
 $3
 $4
Expected return on plan assets—
 (9) (1) (8)
Prior service cost amortization—
 2
 —
 1
Settlements—
 —
 —
 —
Net periodic benefit cost$2
 $(3) $2
 $(3)
Assumptions
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below:
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.27% 2.34% 3.65% 2.34%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below:
 December 31, 2017 December 31, 2016
 Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits
Discount rate3.52% 3.10% 3.60% 3.06%
Expected return on assets:       
Tax exempt accounts3.50% 7.00% 3.50% 7.00%
Taxable accountsN/A
 4.50% N/A
 4.50%
Rate of compensation increaseN/A
 N/A
 N/A
 N/A

The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness.
The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below:
  December 31,
  2017 2016
Health care cost trend rate 7.20% 6.73%
Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.99% 4.96%
Year that the rate reaches the ultimate trend rate 2023
 2021
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75%.
The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets.
The fair value of the pension plan assets by asset category at the dates indicated is as follows:
   Fair Value Measurements at December 31, 2017
 Fair Value Total Level 1 Level 2 Level 3
Asset category:       
Mutual funds(1)
$1
 $1
 $—
 $—
Total$1
 $1
 $—
 $—
(1)
Comprised of approximately 100% equities as of December 31, 2017.
   Fair Value Measurements at December 31, 2016
 Fair Value Total Level 1 Level 2 Level 3
Asset category:       
Mutual funds(1)
$12
 $12
 $—
 $—
Total$12
 $12
 $—
 $—
(1)
Comprised of approximately 100% equities as of December 31, 2016.

The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:
   Fair Value Measurements at December 31, 2017
 Fair Value Total Level 1 Level 2 Level 3
Asset category:       
Cash and cash equivalents$33
 $33
 $—
 $—
Mutual funds(1)
146
 146
 —
 —
Fixed income securities70
 —
 70
 —
Total$249
 $179
 $70
 $—
(1)
Primarily comprised of approximately 48% equities, 51% fixed income securities and 1% cash as of December 31, 2017.
   Fair Value Measurements at December 31, 2016
 Fair Value Total Level 1 Level 2 Level 3
Asset category:       
Cash and cash equivalents$23
 $23
 $—
 $—
Mutual funds(1)
134
 134
 —
 —
Fixed income securities91
 —
 91
 —
Total$248
 $157
 $91
 $—
(1)
Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016.
The Level 1 plan assets are valued based on active market quotes.  The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. 
Contributions
We expect to contribute $8 million to pension plans and $10 million to other postretirement plans in 2018.  The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below:
Years 
Pension Benefits - Unfunded Plans (1)
 Other Postretirement Benefits (Gross, Before Medicare Part D)
2018 $8
 $24
2019 6
 23
2020 6
 21
2021 5
 19
2022 4
 17
2023 – 2027 15
 37
(1)     Expected benefit payments of funded pension plans are less than $1 million for the next ten years.
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.


14.RELATED PARTY TRANSACTIONS:
In June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8.
ETE previously paid us to provide services on its behalf and on behalf of other subsidiaries of ETE, which includesincluded the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries.
In connection with the Lake Charles LNG Transaction, ETP agreed to continue to provide management services for ETE through 2015 These agreements expired in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015.2016.
The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets.
The following table summarizes the affiliate revenues on our consolidated statements of operations:
 Years Ended December 31,
 2014 2013 2012
Affiliated revenues$1,117
 $1,550
 $173
 Years Ended December 31,
 2017 2016 2015
Affiliated revenues$697
 $377
 $417

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The following table summarizes the related company balances on our consolidated balance sheets:
 December 31,
 2014 2013
Accounts receivable from related companies:   
ETE$11
 $18
Regency74
 53
Dakota Access Pipeline68
 —
PES6
 7
FGT9
 29
ET Crude Oil10
 24
Lake Charles LNG3
 —
Other29
 34
Total accounts receivable from related companies:$210
 $165
    
Accounts payable to related companies:   
ETE$—
 $8
Regency53
 24
FGT2
 8
Lake Charles LNG2
 —
Other5
 5
Total accounts payable to related companies:$62
 $45
 December 31,
 2017 2016
Accounts receivable from related companies:   
ETE$—
 $22
Sunoco LP219
 96
FGT11
 15
Other88
 76
Total accounts receivable from related companies$318
 $209
    
Accounts payable to related companies:   
Sunoco LP195
 20
Other14
 23
Total accounts payable to related companies$209
 $43
 December 31,
 2017 2016
Long-term notes receivable (payable) – related companies:   
Sunoco LP$85
 $87
Phillips 66—
 (250)
Net long-term notes receivable (payable) – related companies$85
 $(163)


15.
REPORTABLE SEGMENTS:
Our financial statements currently reflect the following reportable segments, which conduct their business in the United States, as follows:
•intrastate transportation and storage;
•interstate transportation and storage;
•midstream;
•liquidsNGL and refined products transportation and services;
•investment in Sunoco Logistics;
•retail marketing;crude oil transportation and services; and
•all other.
Previously, our reportable segments includedThe Partnership previously presented its retail marketing business as a separate segment for NGL transportationreportable segment. Due to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and services, whichcompletion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of December 31, 2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, our investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been combined into our liquids transportation and services segment and includes our operations related to NGL and crude, except for the crude transportation operations that are included in Sunoco Logistics.  The liquids transportation and services segment includes the Bakken crude project, for which capital expenditures had previously been reported in the “All other” segment.
During the fourth quarter 2013, management realigned the composition of our reportable segments, and as a result, our natural gas marketing operations are now aggregated into the “all other”all other segment. These operations wereConsequently, the retail marketing business that was previously reportedconsolidated has also been aggregated in the midstream segment. Based on this change in ourall other segment presentation, we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.all periods presented.
Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales,

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NGL sales and gathering, transportation and other fees. Revenues from our liquidsNGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation, terminalling and other fees. Revenues from our investment in Sunoco Logisticscrude oil transportation and services segment are primarily reflected in crude sales. Revenues from our retail marketingall other segment are primarily reflected in refined product sales.
We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losslosses on extinguishmentextinguishments of debt gain on deconsolidation and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.

The following tables present financial information by segment:
 Years Ended December 31,
 2014 2013 2012
Revenues:     
Intrastate transportation and storage:     
Revenues from external customers$2,652
 $2,250
 $2,012
Intersegment revenues205
 202
 179
 2,857
 2,452
 2,191
Interstate transportation and storage:     
Revenues from external customers1,057
 1,270
 1,109
Intersegment revenues15
 39
 —
 1,072
 1,309
 1,109
Midstream:     
Revenues from external customers1,210
 1,307
 1,757
Intersegment revenues1,713
 942
 196
 2,923
 2,249
 1,953
Liquids transportation and services:     
Revenues from external customers3,790
 2,063
 619
Intersegment revenues121
 64
 31
 3,911
 2,127
 650
Investment in Sunoco Logistics:     
Revenues from external customers17,920
 16,480
 3,109
Intersegment revenues168
 159
 80
 18,088
 16,639
 3,189
Retail marketing:     
Revenues from external customers22,484
 21,004
 5,926
Intersegment revenues3
 8
 —
 22,487
 21,012
 5,926
All other:     
Revenues from external customers2,045
 1,965
 1,170
Intersegment revenues349
 402
 385
 2,394
 2,367
 1,555
Eliminations(2,574) (1,816) (871)
Total revenues$51,158
 $46,339
 $15,702

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 Years Ended December 31,
 2014 2013 2012
Cost of products sold:     
Intrastate transportation and storage$2,169
 $1,737
 $1,394
Midstream2,174
 1,579
 1,273
Liquids transportation and services3,166
 1,655
 361
Investment in Sunoco Logistics17,110
 15,574
 2,885
Retail marketing21,154
 20,150
 5,757
All other2,338
 2,309
 1,496
Eliminations(2,571) (1,800) (900)
Total cost of products sold$45,540
 $41,204
 $12,266
 Years Ended December 31,
 2017 2016 2015
Revenues:     
Intrastate transportation and storage:     
Revenues from external customers$2,891
 $2,155
 $1,912
Intersegment revenues192
 458
 338
 3,083
 2,613
 2,250
Interstate transportation and storage:     
Revenues from external customers915
 946
 1,008
Intersegment revenues19
 23
 17
 934
 969
 1,025
Midstream:     
Revenues from external customers2,510
 2,342
 2,607
Intersegment revenues4,433
 2,837
 2,449
 6,943
 5,179
 5,056
NGL and refined products transportation and services:     
Revenues from external customers8,326
 5,973
 4,569
Intersegment revenues322
 436
 428
 8,648
 6,409
 4,997
Crude oil transportation and services:     
Revenues from external customers11,672
 7,539
 8,980
Intersegment revenues31
 —
 —
 11,703
 7,539
 8,980
All other:     
Revenues from external customers2,740
 2,872
 15,216
Intersegment revenues161
 400
 558
 2,901
 3,272
 15,774
Eliminations(5,158) (4,154) (3,790)
Total revenues$29,054
 $21,827
 $34,292
 Years Ended December 31,
 2014 2013 2012
Depreciation and amortization:     
Intrastate transportation and storage$125
 $122
 $122
Interstate transportation and storage203
 244
 209
Midstream184
 172
 168
Liquids transportation and services113
 91
 53
Investment in Sunoco Logistics296
 265
 63
Retail marketing189
 114
 28
All other20
 24
 13
Total depreciation and amortization$1,130
 $1,032
 $656
 Years Ended December 31,
 2017 2016 2015
Cost of products sold:     
Intrastate transportation and storage$2,327
 $1,897
 $1,554
Midstream4,761
 3,381
 3,264
NGL and refined products transportation and services6,508
 4,553
 3,431
Crude oil transportation and services9,826
 6,416
 8,158
All other2,509
 2,942
 14,029
Eliminations(5,130) (4,109) (3,722)
Total cost of products sold$20,801
 $15,080
 $26,714

 Years Ended December 31,
 2014 2013 2012
Equity in earnings (losses) of unconsolidated affiliates:     
Intrastate transportation and storage$(1) $—
 $4
Interstate transportation and storage151
 142
 120
Midstream—
 —
 (9)
Liquids transportation and services(3) (2) 2
Investment in Sunoco Logistics23
 18
 5
Retail marketing2
 2
 1
All other62
 12
 19
Total equity in earnings of unconsolidated affiliates$234
 $172
 $142

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 Years Ended December 31,
 2014 2013 2012
Segment Adjusted EBITDA:     
Intrastate transportation and storage$500
 $464
 $601
Interstate transportation and storage1,110
 1,269
 1,013
Midstream608
 479
 467
Liquids transportation and services591
 351
 209
Investment in Sunoco Logistics971
 871
 219
Retail marketing731
 325
 109
All other318
 194
 126
Total Segment Adjusted EBITDA4,829
 3,953
 2,744
Depreciation and amortization(1,130) (1,032) (656)
Interest expense, net of interest capitalized(860) (849) (665)
Gain on deconsolidation of Propane Business—
 —
 1,057
Gain on sale of AmeriGas common units177
 87
 —
Goodwill impairment—
 (689) —
Gains (losses) on interest rate derivatives(157) 44
 (4)
Non-cash unit-based compensation expense(58) (47) (42)
Unrealized gains (losses) on commodity risk management activities23
 51
 (9)
Inventory valuation adjustments(473) 3
 (75)
Loss on extinguishment of debt—
 —
 (115)
Non-operating environmental remediation—
 (168) —
Adjusted EBITDA related to discontinued operations(27) (76) (99)
Adjusted EBITDA related to unconsolidated affiliates(674) (629) (480)
Equity in earnings of unconsolidated affiliates234
 172
 142
Other, net(40) 12
 22
Income from continuing operations before income tax expense$1,844
 $832
 $1,820
 Years Ended December 31,
 2017 2016 2015
Depreciation, depletion and amortization:     
Intrastate transportation and storage$147
 $144
 $129
Interstate transportation and storage214
 207
 210
Midstream954
 840
 720
NGL and refined products transportation and services401
 355
 290
Crude oil transportation and services402
 251
 218
All other214
 189
 362
Total depreciation, depletion and amortization$2,332
 $1,986
 $1,929
 December 31,
 2014 2013 2012
Assets:     
Intrastate transportation and storage$4,563
 $4,606
 $4,691
Interstate transportation and storage10,082
 10,988
 11,794
Midstream3,548
 3,133
 4,946
Liquids transportation and services4,581
 4,326
 3,765
Investment in Sunoco Logistics13,619
 11,650
 10,291
Retail marketing8,930
 3,936
 3,926
All other2,898
 5,063
 3,817
Total assets$48,221
 $43,702
 $43,230

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 Years Ended December 31,
 2014 2013 2012
Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis):     
Intrastate transportation and storage$169
 $47
 $37
Interstate transportation and storage411
 152
 133
Midstream667
 565
 1,317
Liquids transportation and services427
 443
 1,302
Investment in Sunoco Logistics2,510
 1,018
 139
Retail marketing259
 176
 58
All other35
 54
 63
Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs$4,478
 $2,455
 $3,049
 Years Ended December 31,
 2017 2016 2015
Equity in earnings (losses) of unconsolidated affiliates:     
Intrastate transportation and storage$(156) $35
 $32
Interstate transportation and storage236
 193
 197
Midstream20
 19
 (19)
NGL and refined products transportation and services33
 41
 29
Crude oil transportation and services4
 (4) (9)
All other19
 (225) 239
Total equity in earnings of unconsolidated affiliates$156
 $59
 $469
 December 31,
 2014 2013 2012
Advances to and investments in unconsolidated affiliates:     
Intrastate transportation and storage$1
 $1
 $2
Interstate transportation and storage1,954
 2,040
 2,142
Midstream—
 —
 1
Liquids transportation and services31
 29
 29
Investment in Sunoco Logistics226
 125
 118
Retail marketing19
 22
 21
All other1,609
 2,219
 1,189
Total advances to and investments in unconsolidated affiliates$3,840
 $4,436
 $3,502
 Years Ended December 31,
 2017 2016 2015
Segment Adjusted EBITDA:     
Intrastate transportation and storage$626
 $613
 $543
Interstate transportation and storage1,098
 1,117
 1,155
Midstream1,481
 1,133
 1,237
NGL and refined products transportation and services1,641
 1,496
 1,179
Crude oil transportation and services1,379
 834
 521
All other487
 540
 882
Total Segment Adjusted EBITDA6,712
 5,733
 5,517
Depreciation, depletion and amortization(2,332) (1,986) (1,929)
Interest expense, net(1,365) (1,317) (1,291)
Gains on acquisitions—
 83
 —
Impairment losses(920) (813) (339)
Losses on interest rate derivatives(37) (12) (18)
Non-cash unit-based compensation expense(74) (80) (79)
Unrealized gains (losses) on commodity risk management activities56
 (131) (65)
Inventory valuation adjustments—
 —
 58
Losses on extinguishments of debt(42) —
 (43)
Adjusted EBITDA related to unconsolidated affiliates(984) (946) (937)
Equity in earnings from unconsolidated affiliates156
 59
 469
Impairment of investments in unconsolidated affiliates(313) (308) —
Other, net148
 115
 23
Income before income tax benefit$1,005
 $397
 $1,366

 December 31,
 2017 2016 2015
Assets:     
Intrastate transportation and storage$5,020
 $5,176
 $4,882
Interstate transportation and storage13,518
 10,833
 11,345
Midstream20,004
 17,873
 17,039
NGL and refined products transportation and services17,600
 14,074
 11,568
Crude oil transportation and services17,736
 15,909
 10,941
All other4,087
 6,240
 9,353
Total assets$77,965
 $70,105
 $65,128
 Years Ended December 31,
 2017 2016 2015
Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis):     
Intrastate transportation and storage$175
 $76
 $105
Interstate transportation and storage726
 280
 866
Midstream1,308
 1,255
 2,174
NGL and refined products transportation and services2,971
 2,198
 2,853
Crude oil transportation and services453
 1,841
 1,358
All other268
 160
 811
Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis)$5,901
 $5,810
 $8,167
 December 31,
 2017 2016 2015
Advances to and investments in unconsolidated affiliates:     
Intrastate transportation and storage$85
 $399
 $406
Interstate transportation and storage2,118
 2,149
 2,516
Midstream126
 111
 117
NGL and refined products transportation and services234
 235
 258
Crude oil transportation and services22
 18
 21
All other1,231
 1,368
 1,685
Total advances to and investments in unconsolidated affiliates$3,816
 $4,280
 $5,003


16.QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized unaudited quarterly financial data is presented below. The sum of net income per Limited Partner unit by quarter does not equal the net income per limited partner unit for the year due to the computation of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts.
 Quarters Ended   Quarters Ended  
 March 31 June 30 September 30 December 31 Total Year March 31* June 30* September 30* December 31 Total Year
2014:          
2017:          
Revenues $12,232
 $13,029
 $13,618
 $12,279
 $51,158
 $6,895
 $6,576
 $6,973
 $8,610
 $29,054
Gross profit 1,366
 1,393
 1,494
 1,365
 5,618
Operating income 688
 736
 668
 383
 2,475
 683
 736
 779
 199
 2,397
Net income 491
 581
 447
 34
 1,553
 393
 296
 715
 1,097
 2,501
Common Unitholders’ interest in net income (loss) 253
 295
 148
 (90) 606
 32
 (49) 335
 668
 986
Basic net income (loss) per Common Unit $0.76
 $0.92
 $0.44
 $(0.28) $1.77
 $0.03
 $(0.04) $0.29
 $0.57
 $0.94
Diluted net income (loss) per Common Unit $0.76
 $0.92
 $0.44
 $(0.28) $1.77
 $0.03
 $(0.04) $0.29
 $0.57
 $0.93

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 Quarters Ended   Quarters Ended  
 March 31 June 30 September 30 December 31 Total Year March 31* June 30* September 30* December 31* Total Year*
2013:          
2016:          
Revenues $10,854
 $11,551
 $11,902
 $12,032
 $46,339
 $4,481
 $5,289
 $5,531
 $6,526
 $21,827
Gross profit 1,260
 1,322
 1,248
 1,305
 5,135
Operating income (loss) 534
 632
 526
 (151) 1,541
Net income (loss) 424
 413
 404
 (473) 768
Operating income 598
 708
 594
 (139) 1,761
Net income 360
 465
 94
 (336) 583
Common Unitholders’ interest in net income (loss) 194
 165
 209
 (666) (98) (71) 58
 (252) (754) (1,019)
Basic net income (loss) per Common Unit $0.63
 $0.53
 $0.55
 $(1.90) $(0.18) $(0.11) $0.06
 $(0.34) $(0.97) $(1.38)
Diluted net income (loss) per Common Unit $0.63
 $0.53
 $0.55
 $(1.90) $(0.18) $(0.11) $0.06
 $(0.34) $(0.97) $(1.38)
* As adjusted. See Note 2. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality.
The three months ended December 31, 20142017 and 2016 reflected the unfavorable impactsrecognition of $456impairment losses of $920 million and $813 million, respectively. Impairment losses in 2017 were primarily related to non-cash inventory valuation adjustmentsour Trunkline, SUG Holdings, CDM, Sea Robin and refined products reporting units. Impairment losses in 2016 were primarily inrelated to our investment in Sunoco LogisticsPEPL reporting unit, Sea Robin reporting unit and retail marketing segments.midstream midcontinent operations. The three months ended December 31, 20132017 and September 30, 2016 reflected ETP’sthe recognition of a goodwillnon-cash impairment of $689 million.our investments in subsidiaries of $313 million and $308 million, respectively, in our interstate transportation and storage segment.
For the three months ended December 31, 2014 and 2013,certain periods reflected above, distributions paid for the period exceeded net income attributable to partners by $544 million and $1.12 billion, respectively.partners. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.



S - 74

2.17.REGENCY ENERGY PARTNERS LPCONSOLIDATING GUARANTOR FINANCIAL STATEMENTSINFORMATION

Prior to the Sunoco Logistics Merger, Sunoco Logistics Partners Operations L.P., a subsidiary of Sunoco Logistics was the issuer of multiple series of senior notes that were guaranteed by Sunoco Logistics. Subsequent to the Sunoco Logistics Merger, these notes continue to be guaranteed by the parent company.
These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Partners, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
ReportThe following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of Independent Registered Public Accounting Firm

S - 78
Consolidated Balance Sheets – December 31, 2014 and 2013S - 79
Consolidated Statements of Operations – Years Ended December 31, 2014, 2013 and 2012S - 81
Consolidated Statements of Comprehensive Income – Years Ended December 31, 2014, 2013 and 2012S - 82
Consolidated Statements of Cash Flows – Years Ended December 31, 2014, 2013 and 2012S - 83
Consolidated Statements of Partners’ Capital and Noncontrolling Interest
– Years Ended December 31, 2014, 2013 and 2012		S - 85
Notes to Consolidated Financial StatementsS - 87



S - 75

Introductory Statement
References in this report to the “Partnership,” “we,” “our,” “us” and similar terms refer to Regency Energy Partners LP and its subsidiaries. We use the following definitionscondensed consolidating information, the Parent Guarantor’s investments in these consolidated financial statements and footnotes:
NameDefinition or Description
2018 Notes$600 million of 6.875% senior notes with original maturity on December 1, 2018
AOCIAccumulated Other Comprehensive Income (Loss)
Aqua - PVRAqua - PVR Water Services, LLC
AROAsset Retirement Obligation
APMAnadarko Pecos Midstream LLC
BarclaysBarclays Capital Inc.
bpsBasis points
CitiCitigroup Global Markets Inc.
CMChesapeake West Texas Processing, L.L.C.
Coal HandlingCoal Handling Solutions LLC, Kingsport Handling LLC, and Kingsport Services LLC, now known as Materials Handling Solutions LLC
Eagle RockEagle Rock Energy Partners, L.P.
EFS HaynesvilleEFS Haynesville, LLC, a wholly-owned subsidiary of GECC
ELGEdwards Lime Gathering LLC and its wholly-owned subsidiaries ELG Oil LLC and ELG Utility LLC
EPDEnterprise Products Partners L.P.
ETCEnergy Transfer Company, the name assumed by La Grange Acquisition, L.P. for conducting business and shared services, a wholly-owned subsidiary of ETP
ETEEnergy Transfer Equity, L.P.
ETE Common HoldingsETE Common Holdings, LLC, a wholly-owned subsidiary of ETE
ETE GPETE GP Acquirer LLC
ETPEnergy Transfer Partners, L.P.
ETP GPEnergy Transfer Partners GP, LP
Exchange ActSecurities Exchange Act of 1934, as amended
FASBFinancial Accounting Standards Board
FASB ASCFASB Accounting Standards Codification
Finance Corp.Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership
GAAPAccounting principles generally accepted in the United States of America
General PartnerRegency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP, which effectively manages the business and affairs of the Partnership through its board of directors and Regency Employees Management LLC
Grey RanchGrey Ranch Plant LP, a former joint venture of the Partnership
Gulf StatesGulf States Transmission LLC, a wholly-owned subsidiary of the Partnership
HoldcoETP Holdco Corporation
HooverHoover Energy Partners, LP
HPCRIGS Haynesville Partnership Co. and its wholly-owned subsidiary, Regency Intrastate Gas LP
IDRsIncentive Distribution Rights
IRSInternal Revenue Service
KMPKinder Morgan Energy Partners, L.P.
LDHLDH Energy Asset Holdings LLC
LIBORLondon Interbank Offered Rate
Lone StarLone Star NGL LLC
LTIPLong-Term Incentive Plan

S - 76

NameDefinition or Description
MEPMidcontinent Express Pipeline LLC
Mi Vida JVMi Vida JV LLC
MLPMaster Limited Partnership
NGLsNatural gas liquids, including ethane, propane, normal butane, iso butane and natural gasoline
NMEDNew Mexico Environmental Development
NYSENew York Stock Exchange
ORSOhio River System LLC
PADEPPennsylvania Department of Environmental Protection
PartnershipRegency Energy Partners LP
PEPLPanhandle Eastern Pipe Line Company, LP
PEPL HoldingsPEPL Holdings, LLC, a former wholly-owned subsidiary of Southern Union that merged into PEPL
PVRPVR Partners, L.P.
Ranch JVRanch Westex JV LLC
Regency WesternRegency Western G&P LLC, a wholly-owned subsidiary of the Partnership
RGSRegency Gas Services, LP, a wholly-owned subsidiary of the Partnership
RIGSRegency Intrastate Gas System
SECSecurities and Exchange Commission
Securities ActSecurities Act of 1933, as amended
Senior NotesThe collective of 2019 Notes, 2020 Notes, 2020 PVR Notes, 2021 Notes, 2021 PVR Notes, 2022 Notes, October 2022 Notes, 2023 4.5% Notes and 2023 5.5% Notes
Series A Preferred UnitsSeries A convertible redeemable preferred units
Services Co.ETE Services Company, LLC
Southern UnionSouthern Union Company
SUGSSouthern Union Gas Services
SUNSunoco LP (formerly known as Susser, L.P.)
Sweeny JVSweeny Gathering, L.P.
SXLSunoco Logistics Partners L.P.
TCEQTexas Commission on Environmental Quality
U.S.United States
Wells FargoWells Fargo Securities, LLC
WTIWest Texas Intermediate Crude


S - 77


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners
Regency Energy Partners LP
We have audited the accompanying consolidated balance sheets of Regency Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, cash flows, and partners’ capital and noncontrolling interest for each of the three yearsSubsidiary Issuer’s investments in the period ended December 31, 2014. These financial statementsits subsidiaries are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Midcontinent Express Pipeline LLC, a 50 percent owned investee company, the Partnership’s investment in which is accounted for under the equity method of accounting. The Partnership’s investment in Midcontinent Express Pipeline LLC as of December 31, 2014 and 2013 was $695 million and $549 million, respectively, and its equity inTo present the earnings of Midcontinent Express Pipeline LLC was $45 million, $40 million, and $42 million, respectively, for each ofsupplemental condensed consolidating financial information on a comparable basis, the three years in theprior period ended December 31, 2014. Those statements were audited by other auditors, whose reportfinancial information has been furnished to us, and our opinion, insofar as it relates to the amounts included for Midcontinent Express Pipeline LLC, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Regency Energy Partners LP and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2014, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2015 (not separately included herein) expressed an unqualified opinion thereon.

/s/ GRANT THORNTON LLP

Dallas, Texas
February 26, 2015

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REGENCY ENERGY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

 December 31,
 2014 2013
ASSETS   
Current Assets:   
Cash and cash equivalents$24
 $19
Trade accounts receivable, net of allowance for doubtful accounts of $7 and $1483
 292
Related party receivables45
 28
Inventories67
 42
Derivative assets75
 3
Other current assets9
 16
Total current assets703
 400
Property, Plant and Equipment:   
Gathering and transmission systems5,207
 1,671
Compression equipment2,378
 1,627
Gas plants and buildings386
 825
Other property, plant and equipment679
 414
Natural resources454
 —
Construction-in-progress1,156
 513
Total property, plant and equipment10,260
 5,050
Less accumulated depreciation and depletion(1,043) (632)
Property, plant and equipment, net9,217
 4,418
Other Assets:   
Investments in unconsolidated affiliates2,418
 2,097
Other, net of accumulated amortization of debt issuance costs of $28 and $24103
 57
Total other assets2,521
 2,154
Intangible Assets and Goodwill:   
Intangible assets, net of accumulated amortization of $212 and $1073,439
 682
Goodwill1,223
 1,128
Total intangible assets and goodwill4,662
 1,810
TOTAL ASSETS$17,103
 $8,782

















S - 79




REGENCY ENERGY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

 December 31,
 2014 2013
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST   
Current Liabilities:   
Drafts payable$15
 $26
Trade accounts payable529
 291
Related party payables64
 69
Accrued expenses43
 25
Accrued interest81
 38
Other current liabilities24
 26
Total current liabilities756
 475
Long-term derivative liabilities16
 19
Other long-term liabilities72
 30
Long-term debt, net6,641
 3,310
Commitments and contingencies   
Series A Preferred Units, redemption amount of $38 and $3833
 32
Partners’ Capital and Noncontrolling Interest:   
Common units (412,681,151 and 214,287,955 units authorized; 409,406,482 and 210,850,232 units issued and outstanding at December 31, 2014 and 2013)8,531
 3,886
Class F units (6,274,483 units authorized, issued and outstanding at December 31, 2014 and 2013)153
 146
General partner interest781
 782
     Total partners’ capital9,465
 4,814
Noncontrolling interest120
 102
Total partners’ capital and noncontrolling interest9,585
 4,916
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST$17,103
 $8,782

S - 80

REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except unit data and per unit data)
 Years Ended December 31,
 2014 2013 2012
REVENUES     
Gas sales, including related party amounts of $80, $71, and $42$1,903
 $826
 $508
NGL sales, including related party amounts of $282, $81, and $281,741
 1,053
 991
Gathering, transportation and other fees, including related party amounts of $23, $26, and $29989
 545
 401
Net realized and unrealized gain (loss) from derivatives93
 (8) 23
Other225
 105
 77
Total revenues4,951
 2,521
 2,000
OPERATING COSTS AND EXPENSES     
Cost of sales, including related party amounts of $66, $56, and $353,452
 1,793
 1,387
Operation and maintenance448
 296
 228
General and administrative158
 88
 100
(Gain) loss on asset sales, net(1) 2
 3
Depreciation, depletion and amortization541
 287
 252
Goodwill impairment370
 —
 —
Total operating costs and expenses4,968
 2,466
 1,970
OPERATING (LOSS) INCOME(17) 55
 30
Income from unconsolidated affiliates195
 135
 105
Interest expense, net(304) (164) (122)
Loss on debt refinancing, net(25) (7) (8)
Other income and deductions, net12
 7
 29
(LOSS) INCOME BEFORE INCOME TAXES(139) 26
 34
Income tax expense (benefit)3
 (1) —
NET (LOSS) INCOME$(142) $27
 $34
Net income attributable to noncontrolling interest(15) (8) (2)
NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP$(157) $19
 $32
         Amounts attributable to Series A preferred units4
 6
 10
         General partner’s interest, including IDRs31
 11
 9
         Beneficial conversion feature for Class F units7
 4
 —
         Pre-acquisition loss from SUGS allocated to predecessor equity—
 (36) (14)
Limited partners’ interest in net (loss) income$(199) $34
 $27
Basic and diluted (loss) income per common unit:     
         Limited partners’ interest in net (loss) income$(199) $34
 $27
         Weighted average number of common units outstanding348,070,121
 196,227,348
 167,492,735
         Basic (loss) income per common unit$(0.57) $0.17
 $0.16
         Diluted (loss) income per common unit$(0.57) $0.17
 $0.13
         Distributions per common unit$1.975
 $1.87
 $1.84
Amount allocated to beneficial conversion feature for Class F units$7
 $4
 $—
         Total number of Class F units outstanding6,274,483
 6,274,483
 —
         Income per Class F unit due to beneficial conversion feature$1.08
 $0.72
 $—

S - 81

REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(Dollars in millions)

 Years Ended December 31,
 2014 2013 2012
Net (loss) income$(142) $27
 $34
Other comprehensive income:     
Net cash flow hedge amounts reclassified to earnings—
 —
 6
Change in fair value of cash flow hedges—
 —
 (4)
Total other comprehensive income$—
 $—
 $2
Comprehensive (loss) income$(142) $27
 $36
Comprehensive income attributable to noncontrolling interest15
 8
 2
Comprehensive (loss) income attributable to Regency Energy Partners LP$(157) $19
 $34









































S - 82

REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Years Ended December 31,
 2014 2013 2012
OPERATING ACTIVITIES     
Net (loss) income$(142) $27
 $34
Reconciliation of net (loss) income to net cash flows provided by operating activities:     
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization525
 293
 259
Income from unconsolidated affiliates(195) (135) (105)
Derivative valuation changes(93) 6
 (12)
(Gain) loss on asset sales, net(1) 2
 3
Unit-based compensation expenses10
 7
 5
Revaluation of unconsolidated affiliate upon acquisition(6) —
 —
Goodwill impairment370
 —
 —
Cash flow changes in current assets and liabilities:     
Trade accounts receivable and related party receivables28
 (96) —
Other current assets and other current liabilities34
 (54) 10
Trade accounts payable and related party payables(16) 119
 18
Distributions of earnings received from unconsolidated affiliates204
 142
 121
Cash flow changes in other assets and liabilities1
 125
 (9)
Net cash flows provided by operating activities719
 436
 324
INVESTING ACTIVITIES     
Capital expenditures(1,088) (1,034) (560)
Contributions to unconsolidated affiliates(355) (148) (356)
Distributions in excess of earnings of unconsolidated affiliates68
 249
 83
Acquisitions, net of cash received(805) (475) —
Proceeds from asset sales11
 15
 26
Net cash flows used in investing activities(2,169) (1,393) (807)
FINANCING ACTIVITIES     
Borrowings (repayments) under revolving credit facility, net380
 318
 (140)
Proceeds from issuance of senior notes1,580
 1,000
 700
Redemptions of senior notes(983) (163) (88)
Debt issuance costs(31) (24) (15)
Partner distributions and distributions on unvested unit awards(706) (386) (322)
Noncontrolling interest contributions, net of distributions3
 17
 42
Contributions from previous parent—
 —
 51
Drafts payable(11) 18
 4
Common units issued under unit offerings, equity distribution program and LTIP, net of issuance costs, forfeitures and tax withholding1,227
 149
 311
Distributions to Series A Preferred Units(4) (6) (8)
Net cash flows provided by financing activities1,455
 923
 535

S - 83

REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Years Ended December 31,
 2014 2013 2012
Net change in cash and cash equivalents5
 (34) 52
Cash and cash equivalents at beginning of period19
 53
 1
Cash and cash equivalents at end of period$24
 $19
 $53
      
Supplemental cash flow information:     
Accrued capital expenditures$102
 $60
 $136
Issuance of Class F and common units in connection with SUGS Acquisition—
 961
 —
Issuance of common units in connection with PVR, Hoover, and Eagle Rock acquisitions4,281
 —
 —
Long-term debt assumed in PVR Acquisition1,887
 —
 —
Long-term debt exchanged in connection with the Eagle Rock Midstream Acquisition499
 —
 —
Interest paid, net of amounts capitalized303
 146
 112
Accrued capital contribution to unconsolidated affiliate—
 13
 23


S - 84

REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
AND NONCONTROLLING INTEREST
(Dollars in millions)
 Regency Energy Partners LP    
 
Common
Units
 Class F Units 
General
Partner
Interest
 Predecessor Equity AOCI 
Non-controlling
Interest
 Total
Balance - December 31, 2011$3,173
 $—
 $330
 $—
 $(5) $33
 $3,531
Common unit offerings, net of costs297
 —
 —
 —
 —
 —
 297
Issuance of common units under equity distribution program, net of costs15
 —
 —
 —
 —
 —
 15
Common units issued under LTIP, net of forfeitures and tax withholding(1) —
 —
 —
 —
 —
 (1)
Unit-based compensation expenses5
 —
 —
 —
 —
 —
 5
Partner distributions(309) —
 (13) —
 —
 —
 (322)
Net income (loss)37
 —
 9
 (14) —
 2
 34
Noncontrolling interest contributions, net of distributions—
 —
 —
 —
 —
 42
 42
Distributions to Series A Preferred Units(8) —
 —
 —
 —
 —
 (8)
Accretion of Series A Preferred Units(2) —
 —
 —
 —
 —
 (2)
Net cash flow hedge amounts reclassified to earnings—
 —
 —
 —
 5
 —
 5
Contribution of net investment to unitholders—
 —
 —
 1,747
 (3) —
 1,744
Balance - December 31, 2012$3,207
 $—
 $326
 $1,733
 $(3) $77
 $5,340
Contribution of net investment to the Partnership—
 —
 1,925
 (1,928) 3
 —
 —
Issuance of common units in connection with the SUGS Acquisition, net of costs819
 —
 (819) —
 —
 —
 —
Issuance of Class F units in connection with the SUGS Acquisition, net of costs—
 142
 (142) —
 —
 —
 —
Contribution of assets between entities under common control below historical cost—
 —
 (504) 231
 —
 —
 (273)
Issuance of common units under equity distribution program, net of costs149
 —
 —
 —
 —
 —
 149
Conversion of Series A Preferred Units for common units41
 —
 —
 —
 —
 —
 41
Unit-based compensation expenses7
 —
 —
 —
 —
 —
 7
Partner distributions and distributions on unvested unit awards(371) —
 (15) —
 —
 —
 (386)
Noncontrolling interest contributions, net of distributions—
 —
 —
 —
 —
 17
 17
Net income (loss)40
 4
 11
 (36) —
 8
 27
Distributions to Series A Preferred Units(6) —
 —
 —
 —
 —
 (6)
Balance - December 31, 2013$3,886
 $146
 $782
 $—
 $—
 $102
 $4,916


S - 85

REGENCY ENERGY PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
AND NONCONTROLLING INTEREST
(Dollars in millions)

 Regency Energy Partners LP    
 
Common
Units
 Class F Units 
General
Partner
Interest
 
Noncontrolling
Interest
 Total
Balance - December 31, 2013$3,886
 $146
 $782
 $102
 $4,916
Issuance of common units under equity distribution program, net of costs428
 —
 —
 —
 428
Issuance of common units to ETE Common Holdings800
 —
 —
 —
 800
Issuance of common units in connection with Hoover Acquisition109
 —
 —
 —
 109
Issuance of common units in connection with PVR Acquisition3,906
 —
 —
 —
 3,906
Issuance of common units in connection with Eagle Rock Midstream Acquisition266
 —
 —
 —
 266
Common units issued under LTIP, net of forfeitures and tax withholding(1) —
 —
 —
 (1)
Unit-based compensation expenses10
 —
 —
 —
 10
Partner distributions and distributions on unvested unit awards(674) —
 (32) —
 (706)
Noncontrolling interest contributions, net of distributions—
 —
 —
 3
 3
Net (loss) income(195) 7
 31
 15
 (142)
Distributions to Series A Preferred Units(4) —
 —
 —
 (4)
Balance - December 31, 2014$8,531
 $153
 $781
 $120
 $9,585

S - 86

REGENCY ENERGY PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar amounts, except unit and per unit data, are in millions)

1. ORGANIZATION AND BASIS OF PRESENTATION
Organization. The consolidated financial statements presented herein contain the results of Regency Energy Partners LP and its subsidiaries (the “Partnership”), a Delaware limited partnership. The Partnership was formed on September 8, 2005, and completed its IPO on February 3, 2006. The Partnership and its subsidiaries are engaged in the business of gathering and processing, compression, treating and transportation of natural gas; the transportation, fractionation and storage of NGLs; the gathering, transportation and terminaling of oil (crude and/or condensate, a lighter oil) received from producers; natural gas and NGL marketing and trading; and the management of coal and natural resource properties in the United States. Regency GP LP is the Partnership’s general partner and Regency GP LLC (collectively the “General Partner”) is the managing general partner of the Partnership and the general partner of Regency GP LP.
Pending Merger with ETP. On January 25, 2015, the Partnership and ETP entered into the Merger Agreement pursuant to which the Partnership will merge with a wholly-owned subsidiary of ETP, with the Partnership continuing as the surviving entity and becoming a wholly-owned subsidiary of ETP (the “Merger”). At the effective time of the Merger (the “Effective Time”), each Partnership common unit and Class F unit will be converted into the right to receive 0.4066 ETP common units, plus a number of additional ETP common units equal to $0.32 per Partnership unit divided by the lesser of (i) the volume weighted average price of ETP common units for the five trading days ending on the third trading day immediately preceding the Effective Time and (ii) the closing price of ETP common units on the third trading day immediately preceding the Effective Time, rounded to the nearest ten thousandth of a unit. Each Series A Preferred Unit will be converted into the right to receive a preferred unit representing a limited partner interest in ETP, a new class of units in ETP to be established at the Effective Time. Early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, for the Merger was granted by the United States Federal Trade Commission on February 24, 2015. The transaction is expected to close in the second quarter of 2015 and is subject to other customary closing conditions including approval by the Partnership’s unitholders.
Basis of presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year numbers have been conformed to the current year presentation.
Reclassifications. During 2014, the Partnership reclassified amounts within property, plant and equipment asset categories. These reclassifications did not have any impact on amounts recorded for depreciation, depletion or amortization in 2014, and because the reclassified amounts have no significant effect on our consolidated balance sheets, prior period balances have not been adjusted for comparability purposes.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates. These consolidated financial statements have been prepared in conformity with GAAP, which includes the use of estimates and assumptions by management that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could be different from those estimates.
Common Control Transactions. Entities and assets acquired from ETE and its affiliates are accounted for as common control transactions whereby the net assets acquired are combined with the Partnership’s net assets at their historical amounts. If consideration transferred differs from the carrying value of the net assets acquired, the excess or deficiency is treated as a capital transaction similar to a dividend or capital contribution. To the extent that such transactions require prior periods to be recast historical net equity amounts prior to the transaction date are reflected in predecessor equity.
Cash and Cash Equivalents. Cash and cash equivalents include temporary cash investments with original maturities of three months or less.
Equity Method Investments. The equity method of accounting is used to account for the Partnership’s interest in investments of greater than 20% voting interest or where the Partnership exerts significant influence over an investee but lacks control over the investee. Even though there is a presumption of a controlling financial interest in Aqua - PVR (because of our 51% ownership), our partner in this joint venture has substantive participating rights and management authority that preclude us from controlling the joint venture. Therefore, it is accounted for as an equity method investment. The Partnership acquired a 50% interest in Coal Handling as part of the PVR Acquisition and purchased the remaining 50% interest effective December 31, 2014 for $16 million, resulting in a gain on the purchase due to the revaluation of the Partnership’s previously held non-controlling interest.

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Inventories. Inventories are valued at the lower of cost or market and include materials and parts primarily utilized by the Contract Services and Gathering & Processing segments.
Property, Plant and Equipment. Property, plant and equipment is recorded at historical cost of construction or, upon acquisition, the fair value of the assets acquired. Gains or losses on sales or retirements of assets are included in operating income unless the disposition is treated as discontinued operations. Natural gas and NGLs used to maintain pipeline minimum pressures is classified as property, plant and equipment. Financing costs associated with the construction of larger assets requiring ongoing efforts over a period of time are capitalized. For the years ended December 31, 2014, 2013 and 2012, the Partnership capitalized interest of $14 million, $2 million and $1 million, respectively. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.
Depreciation expense related to property, plant and equipment was $418 million, $258 million, and $219 million for the years ended December 31, 2014, 2013 and 2012, respectively. In March 2012, the Partnership recorded a $7 million “out-of-period” adjustment to depreciation expense to correct the estimated useful lives of certain assets to comply with its policy.
Depreciation of property, plant and equipment is recorded on a straight-line basis over the following estimated useful lives:
Functional Class of PropertyUseful Lives (Years)
Gathering and Transmission Systems20 - 40
Compression Equipment2 - 30
Gas Plants and Buildings5 - 20
Other Property, Plant and Equipment3 - 15
Depletion expense related to the Natural Resources segment was $11 million for the year ended December 31, 2014. Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by the Partnership’s own geologists. The Partnership’s estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, the Partnership carries out core-hole drilling activities on coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. The Partnership depletes timber using a methodology consistent with the units-of-production method, which is based on the quantity of timber harvested. The Partnership determines depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves.
Intangible Assets. As of December 31, 2014, intangible assets consisted of trade names and customer relations, and are amortized on a straight line basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows. The estimated useful lives range from 8 to 30 years.
The Partnership assesses long-lived assets, including property, plant and equipment and intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to undiscounted future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets. The Partnership did not record any impairment in 2014, 2013, or 2012.
Goodwill. Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in a business combination. Goodwill is not amortized, but is tested for impairment annually based on the carrying values as of November 30 or December 31 depending upon the reporting unit, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. The Partnership has the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. Impairment is indicated when the carrying amount of a reporting unit exceeds its fair value. To estimate the fair value of the reporting units, the Partnership makes estimates and judgments about future cash flows, as well as revenues, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with the Partnership’s most recent forecast. At the time it is determined that an impairment has occurred, the carrying value of the goodwill is written down to its fair value.
In 2014, a $370 million goodwill impairment charge was recorded related to the Permian reporting unit within the Gathering and Processing segment. The decline in estimated fair value of that reporting unit is primarily driven by the significant decline in commodity prices in the fourth quarter of 2014, and the resulting impact to future commodity prices as well as increases in future estimated operations and maintenance expenses. As a result of the Partnership’s determination that the estimated fair value of the reporting unit being less than the carrying value, the Partnership performed the second step of the goodwill impairment assessment,

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which requires the assets and liabilities of the reporting unit to be fair valued on a hypothetical basis.  Any excess value over the estimated fair value of the reporting unit, determined in this case through established valuation techniques such as discounted cash flow methods and market comparable analyses, compared to the hypothetical fair value of all assets and liabilities of the reporting unit is the implied fair value of goodwill.  To the extent that the implied fair value of goodwill is less than the carrying value of goodwill, an impairment is recognized to eliminate any excess carrying amounts. 
No other goodwill impairments were identified or recorded for the Partnership’s other reporting units in 2014. No goodwill impairment charges were incurred in 2013 or 2012.
Other Assets, net. Other assets, net primarily consists of debt issuance costs, which are capitalized and amortized to interest expense, net over the life of the related debt.
Gas Imbalances. Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements are recorded monthly as other current assets or other current liabilities using then current market prices or the weighted average prices of natural gas or NGLs at the plant or system pursuant to imbalance agreements for which settlement prices are not contractually established.
Within certain volumetric limits determined at the sole discretion of the creditor, these imbalances are generally settled by deliveries of natural gas. Imbalance receivables and payables as of December 31, 2014 and 2013 were immaterial.
Asset Retirement Obligations. Legal obligations associated with the retirement of long-lived assets are recorded at fair value at the time the obligations are incurred, if a reasonable estimate of fair value can be made. Present value techniques are used which reflect assumptions such as removal and remediation costs, inflation,  and profit margins that third parties would demand to settle the amount of the future obligation. The Partnership does not include a market risk premium for unforeseeable circumstances in its fair value estimates because such a premium cannot be reliably estimated. Upon initial recognition of the liability, costs are capitalized as a part of the long-lived asset and allocated to expense over the useful life of the related asset. The liability is accreted to its present value each period with accretion being recorded to operating expense with a corresponding increase in the carrying amount of the liability. The ARO assets and liabilities were immaterial as of December 31, 2014.
Environmental. The Partnership’s operations are subject to federal, state and local laws and rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Partnership to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with applicable environmental laws, rules and regulations may expose the Partnership to significant fines, penalties and/or interruptions in operations. The Partnership’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future.
Predecessor Equity. Predecessor equity included on the consolidated statements of partners’ capital and noncontrolling interest represents SUGS member’s capital prior to the acquisition date (April 30, 2013).
Revenue Recognition. The Partnership earns revenue from (i) domestic sales of natural gas, NGLs and condensate, (ii) natural gas, NGL, condensate, and salt water gathering, processing and transportation, (iii) contract compression and treating services, and (iv) coal royalties. Revenue associated with sales of natural gas, NGLs and condensate are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenue associated with transportation and processing fees are recognized when the service is provided. For contract compression and contract treating services, revenue is recognized when the service is performed. For gathering and processing services, the Partnership receives either fees or commodities from natural gas producers depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, the Partnership is paid for its services by keeping a percentage of the NGLs produced and a percentage of the residue gas resulting from processing the natural gas. Under the percentage-of-index contract type, the Partnership earns revenue by purchasing wellhead natural gas at a percentage of the index price and selling processed natural gas and NGLs at a price approximating the index price to third parties. The Partnership generally reports revenue gross in the consolidated statements of operations when it acts as the principal, takes title to the product, and incurs the risks and rewards of ownership. Revenue for fee-based arrangements is presented net, because the Partnership takes the role of an agent for the producers. Allowance for doubtful accounts is determined based on historical write-off experience and specific identification.
Coal Royalties Revenues and Deferred Income. The Partnership recognizes coal royalties revenues on the basis of tons of coal sold by its lessees and the corresponding revenues from those sales. The Partnership does not have access to actual production and revenues information until 30 days following the month of production. Therefore, financial results include estimated revenues and accounts receivable for the month of production. The Partnership records any differences between the actual amounts ultimately received or paid and the original estimates in the period they become finalized. Most lessees must make minimum monthly or

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annual payments that are generally recoverable over certain time periods. These minimum payments are recorded as deferred income. If the lessee recovers a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalties revenues. If a lessee fails to meet its minimum production for certain pre-determined time periods, the deferred income attributable to the minimum payment is recognized as minimum rental revenues, which is a component of other revenues on our consolidated statements of operations. Other liabilities on the balance sheet also include deferred unearned income from a coal services facility lease, which is recognized in other income as it is earned.
Derivative Instruments. The Partnership’s net income and cash flows are subject to volatility stemming from changes in market prices such as natural gas prices, NGLs prices, processing margins and interest rates. The Partnership uses product-specific swaps to create offsetting positions to specific commodity price exposures, and uses interest rate swap contracts to create offsetting positions to specific interest rate exposures. Derivative financial instruments are recorded on the balance sheet at their fair value based on their settlement date. The Partnership employs derivative financial instruments in connection with an underlying asset, liability and/or anticipated transaction and not for speculative purposes. Furthermore, the Partnership regularly assesses the creditworthiness of counterparties to manage the risk of default. As of December 31, 2014 and 2013, no derivative financial instruments were designated as hedges. In the statement of cash flows, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.
Benefits. The Partnership provides medical, dental, and other healthcare benefits to employees. The total amount incurred by the Partnership for the years ended December 31, 2014, 2013 and 2012, was $17 million, $9 million and $9 million, respectively, in operation and maintenance and general and administrative expenses, as appropriate. The Partnership also provides a matching contribution to its employee’s 401(k) accounts which vest immediately upon contribution. The total amount of matching contributions for the years ended December 31, 2014, 2013 and 2012 was $9 million, $7 million and $4 million, respectively, and were recorded in operation and maintenance and general and administrative expenses, as appropriate. The Partnership has no pension obligations or other post-employment benefits. Beginning January 1, 2013, the Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with base compensation below a specified threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service.
Income Taxes. The Partnership is generally not subject to income taxes, except as discussed below, because its income is taxed directly to its partners. The Partnership is subject to the gross margins tax enacted by the state of Texas. The Partnership has one wholly-owned subsidiary that is subject to income tax and provides for deferred income taxes using the asset and liability method. Accordingly, deferred taxes are recorded for differences between the tax and book basis that will reverse in future periods. The Partnership has deferred tax liabilities of $20 million and $22 million as of December 31, 2014 and 2013, respectively, related to the difference between the book and tax basis of property, plant and equipment and intangible assets and they are included in other long-term liabilities in the accompanying consolidated balance sheets. The Partnership follows the guidance for uncertainties in income taxes where a liability for an unrecognized tax benefit is recorded for a tax position that does not meet the “more likely than not” criteria. The Partnership has not recorded any uncertain tax positions meeting the more likely than not criteria as of December 31, 2014 and 2013. The Partnership recognized $3 million for current and deferred federal and state income tax for the year ended December 31, 2014 and an immaterial amount for current and deferred federal and state income tax benefit for the years ended December 31, 2013 and 2012.
Effective with the Partnership’s acquisition of SUGS on April 30, 2013, SUGS is generally no longer subject to federal income taxes and subject only to gross margins tax in the state of Texas. Substantially all previously recorded current and deferred tax liabilities were settled with Southern Union, along with all other intercompany receivables and payables at the date of acquisition.
The Partnership has its 2007 and 2008 tax years under audit by the IRS. Until this matter is fully resolved, it is not known whether any amounts ultimately recorded would be material, or how such adjustments would affect unitholders. The statute of limitations for these audits has been extended to December 31, 2015.
Equity-Based Compensation. The Partnership accounts for common unit options and phantom units by recognizing the grant-date fair value of awards into expense as they are earned, using an estimated forfeiture rate. The forfeiture rate assumption is reviewed annually to determine whether any adjustments to expense are required. Cash restricted units are recorded in other long-term liabilities on our consolidated balance sheet. The fair value of cash restricted units is remeasured at the end of each reporting period, based on the trading price of our common units, and compensation expense is recorded using the straight-line method over the vesting period.
Earnings per Unit. Basic net income per common unit is computed through the use of the two-class method, which allocates earnings to each class of equity security based on their participation in distributions and deemed distributions. Accretion of the Series A Preferred Units is considered as deemed distributions. Distributions and deemed distributions to the Series A Preferred Units reduce the amount of net income available to the general partner and limited partner interests. The general partners’ interest in net income or loss consists of its respective percentage interest, make-whole allocations for any losses allocated in a prior tax year and IDRs. After deducting the General Partner’s interest, the limited partners’ interest in the remaining net income or loss is

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allocated to each class of equity units based on distributions and beneficial conversion feature amounts, if applicable, then divided by the weighted average number of common and subordinated units outstanding in each class of security. Diluted net income per common unit is computed by dividing limited partners’ interest in net income, after deducting the General Partner’s interest, by the weighted average number of units outstanding and the effect of non-vested phantom units, Series A Preferred Units and unit options. For special classes of common units, such as the Class F units issued with a beneficial conversion feature, the amount of the benefit associated with the period is added back to net income and the unconverted class is added to the denominator.
New Accounting Pronouncement. In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, with earlier adoption not permitted. ASU 2014-09 can be adopted either retrospectively to each prior reporting period presented or as a cumulative-effect adjustment as of the date of adoption. The Partnership is currently evaluating the impact, if any, that adopting this new accounting standard will have on our revenue recognition policies.

3. PARTNERS’ CAPITAL AND DISTRIBUTIONS
Units Activity. The changes in common and Class F units were as follows:
 Common Class F 
Balance - December 31, 2011157,437,608
 —
 
Common unit offerings, net of costs12,650,000
 —
 
Issuance of common units under the equity distribution agreement, net of cost691,129
 —
 
Issuance of common units under LTIP, net of forfeitures and tax withholding172,720
 —
 
Balance - December 31, 2012170,951,457
 —
 
Issuance of common units under LTIP, net of forfeitures and tax withholding184,995
 —
 
Issuance of common units under the equity distribution agreement, net of cost5,712,138
 —
 
Conversion of Series A preferred units for common units2,629,223
 —
 
Issuance of common units and Class F units in connection with SUGS Acquisition31,372,419
(1) 
6,274,483
(2) 
Balance - December 31, 2013210,850,232
 6,274,483
 
Issuance of common units under LTIP, net of forfeitures and tax withholding163,054
 —
 
Issuance of common units under the equity distribution agreements14,827,919
 —
 
Issuance of common units in connection with Hoover Acquisition4,040,471
 —
 
Issuance of common units in connection with PVR Acquisition140,388,382
 —
 
Issuance of common units in connection with Eagle Rock Midstream Acquisition8,245,859
 —
 
Issuance of common units to ETE Common Holdings30,890,565
 —
 
Balance - December 31, 2014409,406,482
 6,274,483
 
(1)ETE has agreed to forgo IDR payments on the Partnership common units issued with the SUGS Acquisition for twenty-four months post-transaction closing.
(2)The Class F units are not entitled to participate in the Partnership’s distributions or earnings for twenty-four months post-transaction closing.
Equity Distribution Agreement. In June 2012, the Partnership entered into an equity distribution agreement with Citi under which the Partnership offered and sold common units for an aggregate offering price of $200 million, from time to time through Citi, as sales agent for the Partnership. Sales of these common units made from time to time under the equity distribution agreement were made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and Citi. The Partnership used the net proceeds from the sale of these common units for general partnership purposes. For the years ended December 31, 2014 and 2013, the Partnership received net proceeds of $34 million and $149 million, respectively, from common units sold pursuant to this equity distribution agreement. No amounts remain available to be issued under this agreement and it is no longer effective.
In May 2014, the Partnership entered into an equity distribution agreement with a group of banks and investment companies (the “Managers”) under which the Partnership offered and sold common units for an aggregate offering price of $400 million, from time to time through the Managers, as sales agent for the Partnership. Sales of these units made from time to time under the equity distribution agreement were made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and the Managers. The Partnership used the net proceeds

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from the sale of these units for general partnership purposes. For the year ended December 31, 2014, the Partnership received net proceeds of $395 million from common units sold pursuant to this equity distribution agreement. No amounts remained available to be issues under this agreement and it is no longer effective.
In January 2015, the Partnership entered into an equity distribution agreement with another group of banks and investment companies (the "2015 Managers") under which the Partnership may offer and sell common units for an aggregate offering price of up to $1 billion, from time to time through the 2015 Managers, as sales agent for the Partnership. Sales of these common units made from time to time under the equity distribution agreement will be made by means of ordinary brokers’ transactions on the New York Stock Exchange at market prices, in block transactions, or as otherwise agreed upon by the Partnership and the 2015 Managers. The Partnership may also sell common units to the 2015 Managers as principal for their own accounts at a price agreed upon at the time of sale. Any sale of common units to the 2015 Managers as principal would be pursuant to the terms of a separate agreement between the Partnership and the 2015 Managers. The Partnership intends to use the net proceeds from the sale of these common units for general partnership purposes.
Common Units Sold. In June 2014, the Partnership sold 14.4 million common units to ETE Common Holdings for proceeds of $400 million. Proceeds from the issuance were used to pay down borrowings on the Partnership’s revolving credit facility, to redeem certain senior notes of the Partnership and for general partnership purposes. In July 2014, the Partnership sold 16.5 million common units to ETE Common Holdings for proceeds of $400 million. Proceeds from the issuance were used to fund a portion of the cash consideration paid to Eagle Rock in connection with the Eagle Rock Midstream Acquisition.
Public Common Unit Offerings. In March 2012, the Partnership issued 12,650,000 common units representing limited partner interests in a public offering at a price of $24.47 per common unit, resulting in net proceeds of $297 million. In May 2012, the Partnership used the net proceeds from this offering to redeem 35%, or $88 million, in aggregate principal amounts of its outstanding senior notes due 2016; pay related premium, expenses and accrued interest; and repay outstanding borrowings under the revolving credit facility.
Beneficial Conversion Feature. The Partnership issued 6,274,483 Class F units in connection with the SUGS Acquisition. At the commitment date (February 27, 2013), the sales price of $23.91 per unit represented a $2.19 per unit discount from the fair value of the Partnership’s common units as of April 30, 2013. Under FASB ASC 470-20, “Debt with Conversion and Other Options,” the discount represents a beneficial conversion feature that is treated as a non-cash distribution for purposes of calculating earnings per unit. The beneficial conversion feature is reflected in income per unit using the effective yield method over the period the Class F units are outstanding, as indicated on the statement of operations in the line item entitled “beneficial conversion feature for Class F units.” The Class F units are convertible to common units on a one-for-one basis on May 8, 2015.
Noncontrolling Interest. The Partnership operates ELG, a gas gathering joint venture in south Texas in which other third party companies own a 40% interest, and ORS, a gathering joint venture in Ohio in which a third party company owns a 25% interest, which are reflected on the Partnership’s consolidated balance sheet as noncontrolling interest.
Distributions. The partnership agreement requires the distribution of all of the Partnership’s Available Cash (defined below) within 45 days after the end of each quarter to unitholders of record on the applicable record date, as determined by the General Partner.
Available Cash. Available Cash, for any quarter, generally consists of all cash and cash equivalents on hand at the end of that quarter less the amount of cash reserves established by the general partner to: (i) provide for the proper conduct of the Partnership’s business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to the unitholders and to the General Partner for any one or more of the next four quarters and plus, all cash on hand on that date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made.
General Partner Interest and Incentive Distribution Rights. The General Partner is entitled to its proportionate share of all quarterly distributions that the Partnership makes prior to its liquidation. The General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The General Partner’s initial 2% interest in these distributions has been reduced since the Partnership has issued additional units and the General Partner has not contributed a proportionate amount of capital to the Partnership to maintain its General Partner interest. The General Partner ownership interest as of December 31, 2014 was 0.69%. This General Partner interest is represented by 2,834,381 equivalent units as of December 31, 2014.
The IDRs held by the General Partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. The General Partner’s IDRs are not reduced if the Partnership issues additional units in the future and the general partner does not contribute a proportionate amount of capital to the Partnership to maintain its general partner interest.

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In connection with the SUGS Acquisition, ETE agreed to forgo IDR payments on the Partnership common units issued with this transaction for the twenty-four months post-transaction closing.
Distributions. The Partnership made the following cash distributions per unit during the years ended December 31, 2014 and 2013:
Distribution Date 
Cash Distribution
(per common unit)
November 14, 2014 $0.5025
August 14, 2014 0.490
May 15, 2014 0.480
February 14, 2014 0.475
   
November 14, 2013 $0.470
August 14, 2013 0.465
May 13, 2013 0.460
February 14, 2013 0.460
The Partnership paid a cash distribution of $0.5025 per common unit on February 13, 2015.
4. (LOSS) INCOME PER LIMITED PARTNER UNIT
The following table provides a reconciliation of the numerator and denominator of the basic and diluted (loss) earnings per unit computations for the years ended December 31, 2014, 2013, and 2012.
 Years Ended December 31,
 2014 2013 2012
 
Loss
(Numerator)
 
Units
(Denominator)
 
Per-Unit
Amount
 
Income
(Numerator)
 
Units
(Denominator)
 
Per-Unit
Amount
 
Income
(Numerator)
 
Units
(Denominator)
 
Per-Unit
Amount
Basic (loss) income per unit                 
Limited Partners’ interest in net (loss) income$(199) 348,070,121
 $(0.57) $34
 196,227,348
 $0.17
 $27
 167,492,735
 $0.16
Effect of Dilutive Securities:                 
Common unit options—
 —
   —
 22,714
   —
 10,854
  
Phantom units *—
 —
   —
 357,230
   —
 223,325
  
Series A Preferred Units—
 —
   —
 2,050,854
   (5) 4,658,700
  
Diluted (loss) income per unit$(199) 348,070,121
 $(0.57) $34
 198,658,146
 $0.17
 $22
 172,385,614
 $0.13
__________________
*Amount assumes maximum conversion rate for market condition awards.

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The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive for the period presented:
Year Ended December 31, 2014
Common unit options25,959
Phantom units469,264
Series A Preferred Units2,059,503
The partnership agreement requires that the General Partner shall receive a 100% allocation of income until its capital account is made whole for all of the net losses allocated to it in prior years.
5. ACQUISITIONS
2014
Eagle Rock Midstream Acquisition. On July 1, 2014, the Partnership acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the issuance of 8.2 million Regency common units to Eagle Rock and the assumption of $499 million of Eagle Rock’s 8.375% Senior Notes due 2019. The remainder of the purchase price was funded by $400 million in common units issued to ETE Common Holdings and borrowings under the Partnership’s revolving credit facility. The Partnership accounted for the Eagle Rock Midstream Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. This acquisition complemented the Partnership’s core gathering and processing business and further diversified the Partnership’s geographic presence in the mid-continent region, east Texas and south Texas. Revenues and net income attributable to Eagle Rock’s operations included in the statement of operations for the year ended December 31, 2014 were $903 million and $30 million, respectively.

Management’s evaluation of the assigned fair values is ongoing. The table below represents a preliminary allocation of the total purchase price:
AssetsAt July 1, 2014
Current assets$120
Property, plant and equipment1,295
Other long-term assets4
Goodwill (1)
49
Total Assets Acquired$1,468
Liabilities 
Current liabilities$116
Long-term debt499
Long-term liabilities12
Total Liabilities Assumed$627
  
Net Assets Acquired$841
(1) Goodwill is reported in the Gathering and Processing segment.
The fair values of the assets acquired and liabilities assumed is being determined using various valuation techniques, including the income and market approaches.

PVR Acquisition. On March 21, 2014, the Partnership acquired PVR for a total purchase price of $5.7 billion, including $1.8 billion principal amount of assumed debt (“PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Partnership common units and a one-time cash payment of $36 million, which was funded through borrowings under the Partnership’s revolving credit facility. The PVR Acquisition enhanced the Partnership’s geographic diversity by adding a strategic presence in the Marcellus and Utica shales in the Appalachian Basin and the Granite Wash in the Mid-Continent region. The Partnership accounted for the acquisition of PVR using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Revenues and net income

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attributable to PVR’s operations included in the statement of operations for the year ended December 31, 2014 were $956 million and $166 million, respectively.

Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:
AssetsAt March 21, 2014
Current assets$149
Gathering and transmission systems1,396
Compression equipment342
Gas plants and buildings110
Natural resources454
Other property, plant and equipment229
Construction in process185
Investments in unconsolidated affiliates62
Intangible assets2,717
Goodwill (1)
370
Other long-term assets18
Total Assets Acquired$6,032
Liabilities 
Current liabilities$168
Long-term debt1,788
Premium related to senior notes99
Long-term liabilities30
Total Liabilities Assumed$2,085
  
Net Assets Acquired$3,947
(1) Goodwill is reported in the Gathering and Processing segment.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

Assets.Cash and cash equivalents, accounts receivable, net, other current assets, and construction in process, were valued using a cost basis as this basis approximates fair value due to the current nature of these items. Real property, including gathering and transmission systems, compression equipment, gas plants and buildings, and other property, plant and equipment, were valued based on a combination of the income, market and cost approaches, depending on the type of asset. Coal and timber reserves were valued using the income approach for active coal and timber reserves. The investments in unconsolidated affiliates were valued using the income approach. Intangible assets, other than goodwill, are customer contract related intangibles, which have an average useful life of 30 years, and have been valued using the income approach. The goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized.

Liabilities. The Partnership assumed accounts payable, accrued liabilities, deferred income, and other long-term liabilities as part of the PVR Acquisition. The Partnership determined that the historical cost basis of these liabilities approximated fair value as they comprise normal operating liabilities. The Partnership assumed long-term debt as part of the acquisition, consisting of amounts outstanding under PVR’s revolving credit facility and PVR’s outstanding senior notes. The amount related to the revolving credit facility was valued at historical book value while the senior notes were valued using quoted market prices, which are considered Level 1 inputs.

Change in Control. The PVR Acquisition constituted a change of control for certain PVR employment agreements. Pursuant to the terms of those agreements, certain payments and benefits, including severance payments, were triggered by the PVR Acquisition. The Partnership recorded $10 million of severance payments due to the change in control and recorded $2 million in retention bonuses that were paid to various retained PVR employees upon the expiration of their retention period.


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Hoover Energy Acquisition.On February 3, 2014, the Partnership acquired certain subsidiaries of Hoover for a total purchase price of $293 million, consisting of (i) 4,040,471 common units issued to Hoover and (ii) $184 million in cash, and (iii) $2 million in asset retirement obligations assumed (the “Hoover Acquisition”). The Hoover Acquisition increased the Partnership’s fee-based revenue, expanding its existing footprint in the southern portion of the Delaware Basin in west Texas, and its services to producers into crude and water gathering. A portion of the consideration is in escrow as security for certain indemnification claims. The Partnership financed the cash portion of the purchase price through borrowings under its revolving credit facility. The Partnership accounted for the Hoover Acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date. Revenues and net income attributable to Hoover’s operations included in the statement of operations for the year ended December 31, 2014 were $35 million and less than $1 million, respectively.

Management completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:
AssetsAt February 3, 2014
Accounts receivable, net$5
Gathering and transmission systems60
Compression equipment16
Gas plants and buildings12
Other property, plant, and equipment23
Construction in process6
Intangible assets148
Goodwill (1)
30
Total Assets Acquired$300
Liabilities 
Accounts payable and accrued liabilities$5
Asset retirement obligation2
Total Liabilities Assumed$7
  
Net Assets Acquired$293
(1) Goodwill is reported in the Gathering and Processing segment.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.

Assets.Accounts receivable, net, other current assets, and construction in process were valued using a cost basis as this basis approximates fair value due to the current nature of these items. Real property, including gathering and transmission systems, compression equipment, and other property, plant and equipment, were valued based on a combination of the income, market and cost approaches, depending on the type of asset. Intangible assets, other than goodwill, are customer contract related intangibles, which have an average useful life of 30 years, and have been valued using the income approach. The goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized.

Liabilities. The Partnership assumed accounts payable, accrued liabilities, and an asset retirement obligation as part of the Hoover Acquisition. The Partnership determined that the historical cost basis of the accounts payable and the accrued liabilities approximated fair value as they comprise normal operating liabilities. The asset retirement obligation was valued based on estimates prepared by an independent environmental consulting firm.


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Pro Forma Results of Operations
The following unaudited pro forma consolidated results of operations for the years ended December 31, 2014 and 2013 are presented as if the PVR, Hoover and Eagle Rock Midstream acquisitions had been completed on January 1, 2013. The pro forma information includes adjustments to reflectincremental expenses associated with the fair value adjustments recorded as a result of applying the acquisition method of accounting and incremental interest expense related to the financing of a portion of the purchase price. This pro forma information is not necessarily indicative of the results that would have occurred had the acquisitionsSunoco Logistics Merger occurred on January 1, 2013, nor is it indicative of future results of operations. Actual results for the year ended December 31, 2014 include PVR, Hoover, and the Eagle Rock midstream business from their respective dates of acquisition.
 Years Ended December 31,
 2014 2013
Revenues$5,780
 $4,695
Net loss attributable to the Partnership(252) (195)
    
Basic net loss per Limited Partner unit$(0.76) $(0.50)
Diluted net loss per Limited Partner unit$(0.76) $(0.50)
2013
SUGS Acquisition.In April 2013, the Partnership acquired SUGS from Southern Union, a wholly-owned subsidiary of Holdco, for $1.5 billion (the “SUGS Acquisition”).
The Partnership accounted for the SUGS Acquisition in a manner similar to the pooling of interest method of accounting as it was a transaction between commonly controlled entities. The Partnership retrospectively adjusted its financial statements to include the balances and operations of SUGS for periods March 26, 2012 to April 30, 2013. The SUGS Acquisition did not impact historical earnings per unit as pre-acquisition earnings were allocated to predecessor equity.
The assets acquired and liabilities assumed in the SUGS Acquisition were as follows:
 April 30, 2013
Current assets$113
Property, plant and equipment, net1,608
Goodwill337
Other non-current assets1
Total Assets Acquired$2,059
Less: 
Current liabilities(93)
Non-current liabilities(36)
Net Assets Acquired$1,930


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The following table presents the revenues and net income (loss) for the previously separate entities and combined amounts presented herein:
 Years Ended December 31,
 
     2013 (1)
 2012
Revenues:   
     Partnership$2,253
 $1,339
     SUGS (1)
268
 661
          Combined$2,521
 $2,000
    
Net income (loss):   
     Partnership$63
 $48
     SUGS (1)
(36) (14)
          Combined$27
 $34
(1)
Combined amounts attributable to SUGS include the period from March 26, 2012 to December 31, 2012 for the year ended December 31, 2012, and the period from January 1, 2013 to April 30, 2013 for the year ended December 31, 2013. Subsequent to the closing of the SUGS Acquisition on April 30, 2013, the results of SUGS were attributable to the Partnership.
6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES
The carrying value of the Partnership’s investment in each of the unconsolidated affiliates as of December 31, 2014 and 2013 is as follows:
      December 31,
  Ownership Type 2014 2013
HPC 49.99% General Partner $422
 $442
MEP 50.00% Membership Interest 695
 549
Lone Star 30.00% Membership Interest 1,162
 1,070
Ranch JV 33.33% Membership Interest 38
 36
Aqua - PVR 51.00% Membership Interest 46
 —
Mi Vida JV 50.00% Membership Interest 54
 —
Others (1)
     1
 —
      $2,418
 $2,097
(1) Others includes Coal Handling, Sweeny JV and Grey Ranch
The Partnership’s interests in the Aqua - PVR joint venture was acquired in the PVR Acquisition. In March 2014, the Partnership entered into an agreement, whereby the Partnership’s 50% interest in Grey Ranch was assigned to SandRidge Midstream, Inc., resulting in a cash settlement of $4 million and a loss of $1 million recorded to income from unconsolidated affiliates.
The following tables summarize the changes in the Partnership’s investment activities in each of the unconsolidated affiliates for the years ended December 31, 2014, 2013 and 2012:
 Year Ended December 31, 2014
   HPC 
MEP (2)
 Lone Star Ranch JV Aqua - PVR Mi Vida JV 
Others (4)
Contributions to unconsolidated affiliates$—
 $175
 $114
 $—
 $—
 $54
 $—
Distributions from unconsolidated affiliates(48) (73) (137) (8) (1) —
 (4)
Share of earnings of unconsolidated affiliates’ net income (loss)33
 45
 116
 9
 (4) —
 2
Amortization of excess fair value of investment (1)
(6) —
 —
 —
 —
 —
 —

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 Year Ended December 31, 2013
 
  HPC (3)
 MEP Lone Star Ranch JV 
Others (4)
Contributions to unconsolidated affiliates$—
 $—
 $137
 $2
 $—
Distributions from unconsolidated affiliates(238) (72) (79) (2) —
Share of earnings of unconsolidated affiliates’ net income36
 40
 64
 1
 —
Amortization of excess fair value of investment (1)
(6) —
 —
 —
 —
 Year Ended December 31, 2012
   HPC MEP Lone Star Ranch JV 
Others (4)
Contributions to unconsolidated affiliates$—
 $—
 $343
 $36
 $—
Distributions from unconsolidated affiliates(61) (75) (68) —
 —
Share of earnings of unconsolidated affiliates’ net income (loss)35
 42
 44
 (1) (9)
Amortization of excess fair value of investment (1)
(6) —
 —
 —
 —
__________________
(1)The Partnership’s investment in HPC was adjusted to its fair value on May 26, 2010 and the excess fair value over net book value was comprised of two components: (1) $155 million was attributed to HPC’s long-lived assets and is being amortized as a reduction of income from unconsolidated affiliates over the useful lives of the respective assets, which vary from 15 to 30 years, and (2) $32 million could not be attributed to a specific asset and therefore will not be amortized in future periods.
(2)The Partnership contributed $175 million to MEP in September 2014 for the repayment of MEP’s debt.
(3)HPC entered into a $500 million 5-year revolving credit facility in September 2013, pursuant to which the Partnership pledged its 49.99% equity interest in HPC. Upon closing such credit facility, HPC borrowed $370 million to fund a non-recurring return of investment to its partners of which the Partnership received $185 million. The amount outstanding under this facility was $450 million as of December 31, 2014. The Partnership’s contingent obligation with respect to the outstanding borrowings under this facility was $225 million at December 31, 2014.
(4)Includes Coal Handling, Grey Ranch, and Sweeny JV.

Summarized Financial Information
Consolidated financial statements for HPC, MEP, and Lone Star are filed as exhibits to this Form 10-K. The following tables present aggregated selected balance sheet and income statement data for Ranch JV (on a 100% basis) for all periods presented:
 December 31,
 2014 2013
Current assets$16
 $7
Property, plant and equipment, net95
 100
Other assets4
 4
Total assets$115
 $111
    
Current liabilities$2
 $3
Equity113
 108
Total liabilities and equity$115
 $111
 Years Ended December 31,
 2014 2013 2012
Revenue$41
 $16
 $1
Operating income (loss)29
 4
 (2)
Net income (loss)29
 4
 (2)
7. DERIVATIVE INSTRUMENTS
Policies. The Partnership established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit and interest rates. The General Partner is responsible for delegation

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of transaction authority levels, and the Audit and Risk Committee of the General Partner is responsible for overseeing the management of these risks, including monitoring exposure limits. The Audit and Risk Committee receives regular briefings on exposures and overall risk management in the context of market activities.
Commodity Price Risk. The Partnership is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operations. The prices of these commodities are impacted by changes in supply and demand as well as market forces. Both the Partnership’s profitability and cash flow are affected by the inherent volatility of these commodities which could adversely affect its ability to make distributions to its unitholders. The Partnership manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, the Partnership may not be able to match pricing terms or cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk.
The Partnership has swap contracts settled against certain NGLs, condensate and natural gas market prices.
Marketing & Trading. The Partnership conducts natural gas marketing and trading activities intended to capitalize on favorable price differentials between various receipt and delivery locations. The Partnership enters into both financial derivatives and physical contracts. These financial derivatives, primarily basis swaps, are transacted: (i) to economically hedge subscribed capacity exposed to market rate fluctuations and (ii) to mitigate the price risk related to other purchases and sales of natural gas. By entering into a basis swap, one pricing index is exchanged for another, effectively locking in the margin between the natural gas purchase and sale by removing index spread risk on the combined physical and financial transaction. Changes in the fair value of these financial and physical contracts are recorded as adjustments to natural gas sales and realized (unrealized) gain (loss) from derivatives, as appropriate.
The Partnership has credit exposure to additional counterparties. The Partnership monitors its exposure to any single counterparty and the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership’s natural gas purchase and sale contracts, for certain counterparties, are subject to counterparty netting agreements governing settlement under such natural gas purchase and sales contracts, and when possible, the Partnership nets the open positions of each counterparty.
Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of December 31, 2014, the Partnership had $1.5 billion of outstanding borrowings exposed to variable interest rate risk.
Credit Risk. The Partnership’s resale of NGLs, condensate and natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances any such extension of credit is backed by adequate collateral, such as a letter of credit or parental guarantee from a parent company with potentially better credit.
The Partnership is exposed to credit risk from its derivative contract counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives, and utilizes master netting agreements that allow for netting of swap contract receivables and payables in the event of default by either party. If the Partnership’s counterparties failed to perform under existing swap contracts, the Partnership’s maximum loss as of December 31, 2014 was $82 million, which would be reduced by less than $1 million due to the netting feature. The Partnership has elected to present assets and liabilities under master netting agreements gross on the consolidated balance sheets.
Embedded Derivatives. The Series A Preferred Units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and the Partnership’s call option. These embedded derivatives are accounted for using mark-to-market accounting. The Partnership does not expect the embedded derivatives to affect its cash flows.

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The Partnership’s derivative assets and liabilities, including credit risk adjustments, as of December 31, 2014 and 2013 are detailed below:
 Assets Liabilities
 December 31, December 31,
 2014 2013 2014 2013
Derivatives not designated as cash flow hedges       
Current amounts       
Commodity contracts$75
 $3
 $—
 $9
Long-term amounts       
Commodity contracts10
 1
 —
 —
Embedded derivatives in Series A Preferred Units—
 —
 16
 19
Total derivatives$85
 $4
 $16
 $28
The Partnership’s statements of operations for the years ended December 31, 2014, 2013 and 2012 were impacted by derivative instruments activities as detailed below:
   Years Ended December 31,
   2014 2013 2012
Derivatives in cash flow hedging relationships:  
Change in Value Recognized in AOCI on Derivatives
(Effective Portion)
Commodity derivatives  $—
 $—
 $(4)
Derivatives in cash flow hedging relationships:
Location of Gain/(Loss)
Recognized in Income
 Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)
Commodity derivativesRevenue $—
 $—
 $6
   Years Ended December 31,
   2014 2013 2012
Derivatives not designated in a hedging relationship:
Location of Gain/(Loss)
Recognized in Income
 Amount of Gain/(Loss) from De-designation Amortized from AOCI into Income
Commodity derivativesRevenue $—
 $—
 $(5)
Derivatives not designated in a hedging relationship:
Location of Gain/(Loss)
Recognized in Income
 Amount of Gain/(Loss) Recognized in Income from Derivatives
Commodity derivativesRevenue $93
 $(9) $16
Embedded derivativesOther income & deductions 3
 6
 14
   $96
 $(3) $30

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8. LONG-TERM DEBT
Obligations in the form of senior notes and borrowings under the credit facilities are as follows:
 December 31,
 2014 2013
Senior notes$5,089
 $2,800
Revolving loans1,504
 510
Unamortized premiums and discounts48
 —
Long-term debt$6,641
 $3,310
Availability under revolving credit facility:   
Total credit facility limit$2,000
 $1,200
Revolving loans(1,504) (510)
Letters of credit(23) (14)
Total available$473
 $676
Long-term debt maturities as of December 31, 2014 for each of the next five years are as follows:
Year Ended December 31,Amount
2015$—
2016—
2017—
2018—
20192,003
Thereafter4,590
Total *$6,593
*Excludes a $67 million unamortized premium on the 2020 PVR Notes and the 2021 PVR Notes assumed by the Partnership and a $19 million unamortized discount on the combined 2022 Notes.
Revolving Credit Facility
In the years ended December 31, 2014, 2013 and 2012 the Partnership borrowed $3.86 billion, $1.83 billion and $1.56 billion, respectively, under its revolving credit facility; these borrowings were to fund capital expenditures and acquisitions. During the same periods, the Partnership repaid $3.48 billion, $1.52 billion and $1.70 billion, respectively, with proceeds from equity offerings and issuances of senior notes.
In February 2014, RGS entered into the First Amendment (the "First Amendment") to the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) to, among other things, expressly permit the pending PVR and Eagle Rock Midstream acquisitions, and to increase the commitment base to $1.5 billion and increase the uncommitted incremental facility to $500 million. The First Amendment allowed the Partnership to assume the legacy PVR senior notes that mature prior to the Credit Agreement.
In September 2014, RGS entered into the Second Amendment to the Credit Agreement to, among other things, increase the letter of credit sublimit from $50 million to $100 million, with none of the four individual issuing banks being required to issue letters of credit in excess of $25 million; increase in the general basket of permitted investments from $300 million to $500 million; add provisions permitting investments in ORS, affording it similar treatment to the Partnership’s existing joint ventures; and update various swap agreement provisions to conform to current market standards.

In November 2014, RGS entered into the Seventh Amended and Restated Credit Agreement (the "New Credit Agreement") to increase the commitment to $2 billion and extended the maturity date to November 25, 2019. The material differences between the Credit Agreement and the New Credit Agreement include:

the addition of provisions permitting investments in Mi Vida JV affording it similar treatment to the Partnership’s existing joint ventures;
an increase in certain permitted covenant baskets; and
updates to various pricing terms and the permitted maximum total leverage ratio to reflect the Partnership’s growth.

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In connection with the New Credit Agreement, t­he Partnership capitalized $5 million of net loan fees related to the amendments completed in the year ended December 31, 2014, which are being amortized over the remaining term.
In May 2013, RGS entered into the Credit Agreement to increase the commitment to $1.2 billion with a $300 million uncommitted incremental facility and extended the maturity date to May 21, 2018. The material differences between the Fifth Amended and Restated Credit Agreement and the Credit Agreement include:

A 75 bps decrease in pricing, with an additional 50 bps decrease upon the achievement of an investment grade rating;
No limitation on the maximum amount that the loan parties may invest in joint ventures existing on the date of the credit agreement so long as the Partnership is in pro forma compliance with the financial covenants;
The addition of a “Restricted Subsidiary” structure such that certain designated subsidiaries are not subject to the credit facility covenants and do not guarantee the obligations thereunder or pledge their assets in support thereof;
The addition of provisions such that upon the achievement of an investment grade rating by the Partnership, the collateral package will be released; the facility will become unsecured; and the covenant package will be significantly reduced;
An eight-quarter increase in the permitted Total Leverage Ratio; and
After March 2015, an increase in the permitted total leverage ratio for the two fiscal quarters following any $50 million or greater acquisition.

In connection with the Credit Agreement, the Partnership capitalized $6 million of net loan fees related to this amendment which are being amortized over the remaining term.
Borrowings under the New Credit Agreement are secured by substantially all of the Partnership’s assets and are guaranteed by the Partnership and its consolidated subsidiaries, except for ELG and ORS. The New Credit Agreement and the guarantees thereunder are senior to the Partnership’s and the guarantors’ unsecured obligations.
The outstanding balance under the New Credit Agreement bears interest at LIBOR plus a margin or alternate base rate (equivalent to the U.S. prime lending rate) plus a margin, or a combination of both. The alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50% and an adjusted one-month LIBOR rate plus 1.00%. The applicable margin shall range from 0.50% to 1.25% for base rate loans, 1.50% to 2.25% for Eurodollar loans. The weighted average interest rate on the amounts outstanding under the Partnership’s Credit Agreement was 2.17% as of December 31, 2014 and 2013.
RGS must pay (i) a commitment fee ranging from 0.25% to 0.375% per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit ranging from 1.5% to 2.25% per annum of the average daily amount of such lender’s letter of credit exposure and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.20% per annum of the average daily amount of the letter of credit exposure. These fees are included in interest expense, net in the consolidated statement of operations.
The New Credit Agreement contains financial covenants requiring RGS and its subsidiaries to maintain a debt to consolidated EBITDA (as defined in the credit agreement) ratio less than 5.50, a consolidated EBITDA to consolidated interest expense ratio greater than 2.50 and a secured debt to consolidated EBITDA ratio less than 3.25. At December 31, 2014 and 2013, RGS and its subsidiaries were in compliance with these covenants.
The New Credit Agreement restricts the ability of RGS to pay dividends and distributions other than reimbursements to the Partnership for expenses and payment of dividends to the Partnership for the amount of available cash (as defined) so long as no default or event of default has occurred or is continuing. The New Credit Agreement also contains various covenants that limit (subject to certain exceptions), among other things, the ability of RGS to:

incur indebtedness;
grant liens;
enter into sale and leaseback transactions;
make certain investments, loans and advances;
dissolve or enter into a merger or consolidation;
enter into asset sales or make acquisitions;
enter into transactions with affiliates;
prepay other indebtedness or amend organizational documents or transactions documents (as defined in the New Credit Agreement);
issue capital stock or create subsidiaries; or
engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the New Credit Agreement or reasonable extension thereof.

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In February 2015, RGS exercised the accordion feature of the New Credit Agreement to increase commitments under the revolving credit facility by $500 million to a total of $2.5 billion. The increased commitments will be available pursuant to the same terms and subject to the same interest rates and fees as the existing commitments under the New Credit Agreement.

Senior Notes

The Partnership and Finance Corp. have the following series of senior notes (collectively “Senior Notes”):

$400 million in aggregate principal amount of our 5.75% senior notes due September 1, 2020 (the “2020 Notes“) with interest payable semi-annually in arrears on March 1 and September 1;
$500 million in aggregate principal amount of our 6.5% senior notes due July 15, 2021 (the “2021 Notes“) with interest payable semi-annually in arrears on January 15 and July 15;
$900 million in aggregate principal of our 5.875% senior notes due March 1, 2022 (the “2022 Notes“), issued in February 2014, with interest payable semi-annually in arrears on March 1 and September 1;
$700 million in aggregate principal amount of our 5.5% senior notes due April 15, 2023 (the “2023 5.5% Notes“) with interest payable semi-annually in arrears on April 15 and October 15;
$600 million in aggregate principal amount of our 4.5% senior notes due November 1, 2023 (the “2023 4.5% Notes“) with interest payable semi-annually in arrears on May 1 and November 1;
$390 million, after partial redemption, in aggregate principal amount of our 8.375% senior notes due June 1, 2020 (the “2020 PVR Notes“) with interest payable semi-annually in arrears on June 1 and December 1;
$400 million in aggregate principal amount of our 6.5% senior notes due May 15, 2021 (the “2021 PVR Notes“) with interest payable semi-annually in arrears on May 15 and November 15;
$499 million in aggregate principal amount of our 8.375% senior notes due June 1, 2019 (the “2019 Notes“) with interest payable semi-annually in arrears on June 1 and December 1; and
$700 million in aggregate principal amount of our 5% senior notes due October 1, 2022 (the “October 2022 Notes“) with interest payable semi-annually in arrears on April 1 and October 1.

In May 2009, the Partnership and Finance Corp. issued $250 million of senior notes with a maturity of June 1, 2016 (the “2016 Notes”). The 2016 Notes bore interest at 9.375% with interest payable semi-annually in arrears on June 1 and December 1. In May 2012, the Partnership redeemed 35%, or $88 million, of the 2016 Notes, bringing the total outstanding principal amount to $163 million. A redemption premium of $8 million was charged to loss on debt refinancing, net in the consolidated statements of operations and $4 million of accrued interest was paid. The Partnership also wrote off the unamortized loan fee of $1 million and unamortized bond premium of $2 million to loss on debt refinancing, net in the consolidated statement of operations. In June 2013, the Partnership redeemed all amounts outstanding 2016 Notes for $178 million cash, inclusive of accrued and unpaid interest of $7 million and other fees and expenses.
In February 2014, the Partnership and Finance Corp. issued $900 million of senior notes that mature on March 1, 2022 (the “2022 Notes”). The 2022 Notes bear interest at 5.875% with interest payable semi-annually in arrears on September 1 and March 1. At any time prior to December 1, 2021, the Partnership may redeem some or all of the notes at 100% of the principal amount thereof, plus a “make-whole” redemption price and accrued and unpaid interest, if any, to the redemption date. On or after December 1, 2021, the Partnership may redeem some or all of the 2022 Notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. The 2022 Notes rank equally with the Partnership’s other Senior Notes.

In March 2014, in connection with the PVR Acquisition, the Partnership assumed $1.2 billion in aggregate principal amount of PVR’s outstanding senior notes, consisting of $300 million of 8.25% senior notes that mature on April 15, 2018 (the “2018 PVR Notes”), $400 million of 6.5% senior notes that mature on May 15, 2021 (the “2021 PVR Notes”), and $473 million of 8.375% senior notes that mature on June 1, 2020 (the “2020 PVR Notes”, and together with the 2021 PVR Notes, the "PVR Notes"). In April 2014, the Partnership redeemed all of the 2018 PVR Notes for $313 million at a price of 104.125% plus accrued and unpaid interest paid to the redemption date. Interest on the 2021 PVR Notes and the 2020 PVR Notes accrue semi-annually on May 15 and November 15 and June 1 and December 1, respectively. The PVR Notes rank equally with the Partnership’s other Senior Notes.

On March 24, 2014, in accordance with the Partnership’s obligations under the indentures governing the PVR Notes, the Partnership commenced change of control offers pursuant to which holders of such notes were entitled to require the Partnership to repurchase all or a portion of its PVR Notes at a purchase price of 101% of the principal amount thereof, plus accrued and unpaid interest to the repurchase date. The change of control offers for the PVR Notes expired on April 22, 2014 and, on April 23, 2014, the Partnership accepted for purchase less than $1 million in aggregate principal amount of 2021 PVR Notes.

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In July 2014, in connection with the Eagle Rock Midstream Acquisition, the Partnership exchanged $499 million of 8.375% Senior Notes due 2019 of Eagle Rock and Eagle Rock Energy Finance Corp. for 8.375% Senior Notes due 2019 issued by the Partnership and Finance Corp. (the “New Partnership Notes”). The New Partnership Notes rank equally with the Partnership’s other Senior Notes.

In July 2014, the Partnership and Finance Corp. issued $700 million of senior notes that mature on October 1, 2022 (the “October 2022 Notes”). The October 2022 Notes bear interest at 5% with interest payable semi-annual in arrears on October 1 and April 1, beginning April 1, 2015. At any time prior to July 1, 2022, the Partnership may redeem some or all of the October 2022 Notes at 100% of the principal amount thereof, plus a “make-whole” redemption price and accrued and unpaid interest, if any, to the redemption date. On or after, July 1, 2022, the Partnership may redeem some or all of the October 2022 Notes at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date. The October 2022 Notes rank equally with the Partnership’s other Senior Notes.

In July 2014, the Partnership redeemed $83 million of the $473 million outstanding 2020 PVR Notes for $91 million, including $8 million of accrued interest and redemption premium.

In December 2014, the Partnership redeemed all of the outstanding $600 million 2018 Notes, for a total price of 103.438% or $621 million.

The Senior Notes issued by the Partnership and Finance Corp. are fully and unconditionally guaranteed, on a joint and several
basis, by all of the Partnership’s consolidated subsidiaries, except for ELG and ORS.

The Senior Notes are redeemable at any time prior to the dates specified below at a price equal to 100% of the principal amount of the applicable series, plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date:

2020 Notes - Redeemable, in whole or in part, prior to June 1, 2020 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after June 1, 2020 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date
2021 Notes - Any time prior to July 15, 2014, up to 35% may be redeemed at a price of 106.5% plus accrued and unpaid interest, if any; beginning July 15, 2016, 100% may be redeemed at fixed redemption price of 103.25% (July 15, 2017 - 102.167%, July 15, 2018 - 101.083% and July 15, 2019 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
2022 Notes - Redeemable, in whole or in part, prior to December 1, 2021 at 100% at the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after December 1, 2021 at 100% at the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date
2023 5.5% Notes - Any time prior to October 15, 2015, up to 35% may be redeemed at a price of 105.5% plus accrued and unpaid interest, if any; beginning October 15, 2017, 100% may be redeemed at fixed redemption price of 102.75% (October 15, 2018 - 101.833%, October 15, 2019 - 100.917% and October 15, 2020 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
2023 4.5% Notes - Redeemable, in whole or in part, prior to August 1, 2023 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or after August 1, 2023 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date
2020 PVR Notes - Any time prior to June 1, 2015, up to 35% may be redeemed at a price of 108.375% plus accrued and unpaid interest, if any; beginning June 1, 2016, 100% may be redeemed at fixed redemption price of 104.188% (June 1, 2017 - 102.094%, June 1, 2018 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
2021 PVR Notes - Any time prior to May 15, 2016, up to 35% may be redeemed at a price of 106.5% plus accrued and unpaid interest and liquidated damages, if any; beginning May 15, 2016, 100% may be redeemed at a fixed redemption price of 104.875% (May 15, 2017 - 103.250%, May 15, 2018 - 101.625% and May 15, 2019 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
2019 Notes - Redeemable, in whole or in part, prior to June 1, 2015 at 100% at the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; beginning June 1, 2015, 100% may be redeemed at a fixed redemption price of 104.188% (June 1, 2016 - 102.094% and June 1, 2017 and thereafter - 100%) plus accrued and unpaid interest, if any, to the redemption date
October 2022 Notes - Redeemable, in whole or in part, prior to July 1, 2022 at 100% of the principal amount plus a make-whole premium and accrued and unpaid interest, if any, to the redemption date; redeemable, in whole or in part, on or

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after July 1, 2022 at 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date

Upon a change of control followed by a ratings downgrade within 90 days of a change of control, each holder of the Partnership’s Senior Notes, other than the PVR Notes, will be entitled to require the Partnership to repurchase all or a portion of its notes at a purchase price of 101% plus accrued and unpaid interest, if any. Upon a change of control, the indenture governing the PVR Notes requires the Partnership to make an offer to repurchase all outstanding notes at101%of the principal amount thereof, plus accrued and unpaid interest (and additional interest, if any) to the date of repurchase. The Partnership’s ability to repurchase the Senior Notes upon a change of control will be limited by the terms of our debt agreements, including the Partnership’s revolving credit facility.

The Senior Notes contain various covenants that limit, among other things, the Partnership’s ability, and the ability of certain of the Partnership’s subsidiaries, to:

incur additional indebtedness;
pay distributions on, or repurchase or redeem our equity interests;
make certain investments;
incur liens;
enter into certain types of transactions with affiliates; and
sell assets or consolidate or merge with or into other companies.

If the Senior Notes achieve investment grade ratings by both Moody’s and Standard & Poor’s and no default or event of default has occurred and is continuing, the Partnership will no longer be subject to many of the foregoing covenants. At December 31, 2014, the Partnership was in compliance with these covenants.
9. INTANGIBLE ASSETS
Activity related to intangible assets, net consisted of the following:
 
Customer
Relations
 Trade Names Total
Balance at January 1, 2013$655
 $57
 $712
Amortization(26) (4) (30)
Balance at December 31, 2013629
 53
 682
Amortization(105) (3) (108)
Intangible assets acquired2,865
 —
 2,865
Balance at December 31, 2014$3,389
 $50
 $3,439
The average remaining amortization periods for customer relations and trade names are 28 and 15 years, respectively. The expected amortization of the intangible assets for each of the five succeeding years is $135 million.
10. FAIR VALUE MEASURES
The fair value measurement provisions establish a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:
Level 1—unadjusted quoted prices for identical assets or liabilities in active accessible markets;
Level 2—inputs that are observable in the marketplace other than those classified as Level 1; and
Level 3—inputs that are unobservable in the marketplace and significant to the valuation.
Entities are encouraged to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.
The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are derivatives related to commodity
swaps and embedded derivatives in the Series A Preferred Units. Derivatives related to commodity swaps are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Embedded derivatives related to Series A Preferred Units are valued using

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a binomial lattice model. The inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility, and are classified as Level 3 in the hierarchy.

The following table presents the Partnership’s derivative assets and liabilities measured at fair value on a recurring basis:
 Fair Value Measurement at December 31,
 2014 2013
 
Fair Value
Total
 Level 2 Level 3 
Fair Value
Total
 Level 2 Level 3
Assets           
Commodity Derivatives:           
Natural Gas$26
 $26
 $—
 $2
 $2
 $—
Natural Gas Liquids23
 23
 —
 2
 2
 —
Condensate36
 36
 —
 —
 —
 —
Total Assets$85
 $85
 $—
 $4
 $4
 $—
Liabilities           
Commodity Derivatives:    
      
Natural Gas$—
 $—
 $—
 $4
 $4
 $—
Natural Gas Liquids—
 —
 —
 4
 4
 —
Condensate—
 —
 —
 1
 1
 —
Embedded Derivatives in Series A Preferred Units16
 —
 16
 19
 —
 19
Total Liabilities$16
 $—
 $16
 $28
 $9
 $19

The following table presents the material unobservable inputs used to estimate the fair value of the embedded derivatives in the Series A Preferred Units:
Unobservable InputDecember 31, 2014
Credit Spread4.76%
Volatility35.8%
Changes in the Partnership’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives.
The following table presents the changes in Level 3 derivatives measured on a recurring basis for the years ended December 31, 2014 and 2013. There were no transfers between Level 2 and Level 3 derivatives for the years ended December 31, 2014 and 2013.
 
Embedded Derivatives in
Series A Preferred Units
Balance at January 1, 2013$25
Change in fair value, net of gain at conversion of $26 million(6)
Balance at December 31, 201319
Change in fair value(3)
Balance at December 31, 2014$16
The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Long-term debt, other than the Senior Notes, is comprised of borrowings under which interest accrues under a floating interest rate structure. Accordingly, the carrying value approximates fair value.
The aggregate fair value and carrying amount of the Senior Notes at December 31, 2014 and 2013 was $5.1 billion and $2.8 billion, respectively. The fair value of the Senior Notes is a Level 1 valuation based on third party market value quotations.

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11. LEASES
The following table is a schedule of future minimum lease payments for office space and certain equipment leased by the Partnership, that had initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2014:
For the year ending December 31, Operating Lease
2015 $5
2016 5
2017 4
2018 3
2019 2
Thereafter 26
Total minimum lease payments$45
Total rent expense for operating leases, including those leases with terms of less than one year, was $20 million, $11 million and $11 million for the years ended December 31, 2014, 2013 and 2012, respectively.
12. COMMITMENTS AND CONTINGENCIES
Legal. The Partnership is involved in various claims, lawsuits and audits by taxing authorities incidental to its business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.
ETP Merger Shareholder Litigation.Following the January 26, 2015 announcement of the definitive merger agreement with ETP, purported Partnership unitholders filed lawsuits in state and federal courts in Dallas, Texas asserting claims relating to the proposed transaction.
On February 3, 2015, William Engel and Enno Seago, purported Partnership unitholders, filed a class action petition on behalf of the Partnership’s common unitholders and a derivative suit on behalf of the Partnership in the 162nd Judicial District Court of Dallas County, Texas (the “Engel Lawsuit”). The lawsuit names as defendants the General Partner, the members of the General Partner’s board of directors, ETP, ETP GP, ETE, and, as a nominal party, the Partnership. The Engel Lawsuit alleges that (1) the General Partner’s directors breached duties to the Partnership and the Partnership’s unitholders by employing a conflicted and unfair process and failing to maximize the merger consideration; (2) the General Partner’s directors breached the implied covenant of good faith and fair dealing by engaging in a flawed merger process; and (3) the non-director defendants aided and abetted in these claimed breaches. The plaintiffs seek an injunction preventing the defendants from closing the proposed transaction or an order rescinding the transaction if it has already been completed. The plaintiffs also seek money damages and court costs, including attorney’s fees.
On February 9, 2015, Stuart Yeager, a purported Partnership unitholder, filed a class action petition on behalf of the Partnership’s common unitholders and a derivative suit on behalf of the Partnership in the 134th Judicial District Court of Dallas County, Texas (the “Yeager Lawsuit”). The allegations, claims, and relief sought in the Yeager Lawsuit are nearly identical to those in the Engel Lawsuit.
On February 10, 2015, Lucien Coggia a purported Partnership unitholder, filed a class action petition on behalf of the Partnership’s common unitholders and a derivative suit on behalf of the Partnership in the 192nd Judicial District Court of Dallas County, Texas (the “Coggia Lawsuit”). The allegations, claims, and relief sought in the Coggia Lawsuit are nearly identical to those in the Engel Lawsuit.
On February 3, 2015, Linda Blankman, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Blankman Lawsuit”). The allegations and claims in the Blankman Lawsuit are similar to those in the Engel Lawsuit. However, the Blankman Lawsuit does not allege any derivative claims and includes the Partnership as a defendant rather than a nominal party. The lawsuit also omits one of the General Partner’s directors, Richard Brannon, who was named in the Engel Lawsuit. The Blankman Lawsuit alleges that the General Partner’s directors breached their fiduciary duties to the unitholders by failing to maximize the value of the Partnership, failing to properly value the Partnership, and ignoring conflicts of interest. The plaintiff also asserts a claim against the non-director defendants for aiding and abetting the directors’ alleged breach of fiduciary duty. The Blankman Lawsuit seeks the same relief that the plaintiffs seek in the Engel Lawsuit.

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On February 6, 2015, Edwin Bazini, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Bazini Lawsuit”). The allegations, claims, and relief sought in the Bazini Lawsuit are nearly identical to those in the Blankman Lawsuit.
On February 11, 2015, Mark Hinnau, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Hinnau Lawsuit”). The allegations, claims, and relief sought in the Hinnau Lawsuit are nearly identical to those in the Blankman Lawsuit.
On February 11, 2015, Stephen Weaver, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Weaver Lawsuit”). The allegations, claims, and relief sought in the Weaver Lawsuit are nearly identical to those in the Blankman Lawsuit.
On February 11, 2015, Adrian Dieckman, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Dieckman Lawsuit are similar to those in the Blankman Lawsuit, except that the Dieckman Lawsuit does not assert an aiding and abetting claim.
On February 13, 2015, Irwin Berlin, a purported Partnership unitholder, filed a class action complaint on behalf of the Partnership’s common unitholders in the United States District Court for the Northern District of Texas (the “Dieckman Lawsuit”). The allegations, claims, and relief sought in the Berlin Lawsuit are similar to those in the Blankman Lawsuit.
Each of these lawsuits is at a preliminary stage. We cannot predict the outcome of these or any other lawsuits that might be filed, nor can we predict the amount of time and expense that will be required to resolve these lawsuits. The Partnership and the other defendants named in the lawsuits intend to defend vigorously against these and any other actions.
PVR Shareholder Litigation. Five putative class action lawsuits challenging the PVR Acquisition are currently pending. All of the cases name PVR, PVR GP and the then-incumbent directors of PVR GP, as well as the Partnership and the General Partner (collectively, the “Regency Defendants”), as defendants. Each of the lawsuits has been brought by a purported unitholder of PVR, both individually and on behalf of a putative class consisting of public unitholders of PVR. The lawsuits generally allege, among other things, that the directors of PVR GP breached their fiduciary duties to unitholders of PVR, that PVR GP, PVR and the Regency Defendants aided and abetted the directors of PVR GP in the alleged breach of these fiduciary duties, and, as to the actions in federal court, that some or all of PVR, PVR GP, and the directors of PVR GP violated Section 14(a) of the Exchange Act and Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The lawsuits purport to seek, in general, (i) injunctive relief, (ii) disclosure of certain additional information concerning the transaction, (iii) rescission or an award of rescissory damages, (iv) an award of plaintiffs’ costs and (v) the accounting for damages allegedly causes by the defendants to these actions, and, (vi) such further relief as the court deems just and proper. The styles of the pending cases are as follows: David Naiditch v. PVR Partners, L.P., et al. in the Court of Chancery of the State of Delaware); Charles Monatt v. PVR Partners, LP, et al. and Saul Srour v. PVR Partners, L.P., et al., each pending in the Court of Common Pleas for Delaware County, Pennsylvania; Stephen Bushansky v. PVR Partners, L.P., et al.; and Mark Hinnau v. PVR Partners, L.P., et al., pending in the United States District Court for the Eastern District of Pennsylvania.

On January 28, 2014, the defendants entered into a Memorandum of Understanding (“MOU”) with Monatt, Srour, Bushansky, Naiditch and Hinnau pursuant to which defendants and the referenced plaintiffs agreed in principle to a settlement of their lawsuits (“Settled Lawsuits”), which will be memorialized in a separate settlement agreement, subject to customary conditions, including consummation of the PVR Acquisition, which occurred on March 21, 2014, completion of certain confirmatory discovery (which was completed as of September 5, 2014), class certification and final approval by the Court of Common Pleas for Delaware County, Pennsylvania. If the Court approves the settlement, the Settled Lawsuits will be dismissed with prejudice and all defendants will be released from any and all claims relating to the Settled Lawsuits.

The settlement did not affect any provisions of the merger agreement or the form or amount of consideration received by PVR unitholders in the PVR Acquisition. The defendants have denied and continue to deny any wrongdoing or liability with respect to the plaintiffs’ claims in the aforementioned litigation and have entered into the settlement to eliminate the uncertainty, burden, risk, expense, and distraction of further litigation.
Eagle Rock Shareholder Litigation. Three putative class action lawsuits challenging the Eagle Rock Midstream Acquisition were previously filed in federal district court in Houston, Texas. All cases name Eagle Rock and its current directors, as well as the Partnership and a subsidiary, as defendants. One of the lawsuits also names additional Eagle Rock entities as defendants. Each of the lawsuits has been brought by a purported unitholder of Eagle Rock (collectively, the “Plaintiffs”), both individually and on behalf of a putative class consisting of public unitholders of Eagle Rock. The Plaintiffs in each case seek to rescind the transaction,

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claiming, among other things, that it yields inadequate consideration, was tainted by conflict and constitutes breaches of common law fiduciary duties or contractually imposed duties to the shareholders. Plaintiffs also seek monetary damages and attorneys’ fees. The Partnership and its subsidiary are named as “aiders and abettors” of the allegedly wrongful actions of Eagle Rock and its board. In November 2014, the US District Court issued a Notice of Voluntary Dismissal without Prejudice of all claims in this matter.
PADEP Consent Assessment. On November 21, 2014, our subsidiary, Regency Marcellus Gas Gathering LLC (“Regency Marcellus”), received a Notice of Violation (“NOV”) from the Pennsylvania Department of Environmental Protection (“PADEP”) relating to unpermitted wetlands and streams along the second phase of construction of the Canton Pipeline Project with proposed civil penalties potentially in excess of $100,000. Regency Marcellus has submitted amended permit applications for this phase of construction and is working with the PADEP to acquire amended permits for the proposed crossings of the wetland resources. Regency Marcellus is in discussions with the PADEP regarding the aforementioned NOV. The timing or outcome of this matter cannot reasonably be determined at this time, however we do not expect there to be a material impact on our business or results of operations.
CDM Sales Tax Audit. CDM Resource Management LLC (“CDM”), a subsidiary of the Partnership, has historically claimed the manufacturing exemption from sales tax in Texas, as is common in the industry. The exemption is based on the fact that CDM’s natural gas compression equipment is used in the process of treating natural gas for ultimate use and sale. In a recent audit by the Texas Comptroller’s office, the Comptroller has challenged the applicability of the manufacturing exemption to CDM. The period being audited is from August 2006 to August 2007, and liability for that period is potentially covered by an indemnity obligation from CDM’s prior owners. CDM may also have liability for periods since 2008, and prospectively, if the Comptroller’s challenge is ultimately successful. An audit of the 2008 period has commenced. In April 2013, an independent audit review agreed with the Comptroller’s position. While CDM continues to disagree with this position and intends to seek redetermination and other relief, we are unable to predict the final outcome of this matter.
Environmental. The Partnership is responsible for environmental remediation at certain sites on its gathering and processing systems, resulting primarily from releases of hydrocarbons. The Partnership’s remediation program typically involves the management of contaminated soils and may involve remediation of groundwater. Activities vary with site conditions and locations, the extent and nature of the contamination, remedial requirements and complexity. The ultimate liability and total costs associated with these sites will depend upon many factors. In addition, the Partnership has reclamation and bonding requirements with respect to certain un-leased and inactive coal properties.
The table below reflects the undiscounted environmental liabilities recorded in the consolidated balance sheet at December 31, 2014 and 2013 where management believes a loss is probable and reasonably estimable. The Partnership does not have any material environmental remediation matters assessed as reasonably possible that would require disclosure in the financial statements.
 December 31,
 2014 2013
Current$2
 $2
Noncurrent8
 6
   Total environmental liabilities$10
 $8
The Partnership made expenditures related to environmental remediation of $2 million for the year ended December 31, 2014.
Air Quality Control. The Partnership is currently negotiating settlements to certain enforcement actions by the NMED and the TCEQ. The TCEQ recently initiated a state-wide emissions inventory for the sulfur dioxide emissions from sites with reported emissions of 10 tons per year or more. If this data demonstrates that any source or group of sources may cause or contribute to a violation of the National Ambient Air Quality Standards, they must be sufficiently controlled to ensure timely attainment of the standard. This may potentially affect three recovery units in Texas. It is unclear at this time how the NMED will address the sulfur dioxide standard.
Compliance Orders from the NMED. The Partnership has been in discussions with the NMED concerning allegations of violations of New Mexico air regulations related to the Jal #3 and Jal #4 facilities. Hearings on the compliance orders were delayed until May 2015 to allow the parties to pursue substantive settlement discussions. The Partnership has meritorious defenses to the NMED claims and can offer significant mitigating factors to the claimed violations. The Partnership has recorded a liability of less than $1 million related to the claims and will continue to assess its potential exposure to the allegations as the matters progress.

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Mine Health and Safety Laws. There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since the Partnership does not operate any mines and does not employ any coal miners, it is not subject to such laws and regulations. Accordingly, the Partnership has not accrued any related liabilities.
In addition to the matters discussed above, the Partnership is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business.
13. SERIES A PREFERRED UNITS
On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units for net proceeds of $79 million, inclusive of the General Partner’s contribution of $2 million.
Holders may elect to convert Series A Preferred Units to common units at any time. In July 2013, certain holders of Series A Preferred Units exercised their right to convert 2,459,017 Series A Preferred Units into common units. Concurrent with this transaction, the Partnership recognized a $26 million gain in other income and deductions, net, related to the embedded derivative and reclassified $41 million from the Series A Preferred Units into common units. As of December 31, 2014, the remaining Series A Preferred Units were convertible into 2,064,805 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon (the “Series A Liquidation Value”). The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit if outstanding on the record dates of the Partnership’s common unit distributions.
Distributions on the Series A Preferred Units were accrued for the first two quarters (and not paid in cash) and will result in an increase in the number of common units issuable upon conversion. If on any distribution payment date beginning March 31, 2010, the Partnership (1) fails to pay distributions on the Series A Preferred Units, (2) reduces the distributions on the common units to zero and (3) is prohibited by its material financing agreements from paying cash distributions, such distributions shall automatically accrue and accumulate until paid in cash. If the Partnership has failed to pay cash distributions in full for two quarters (whether or not consecutive) from and including the quarter ended on March 31, 2010, then if the Partnership fails to pay cash distributions on the Series A Preferred Units, all future distributions on the Series A Preferred Units that are accrued rather than being paid in cash by the Partnership will consist of the following: (1) $0.35375 per Series A Preferred Unit per quarter, (2) $0.09125 per Series A Preferred Unit per quarter (the “Common Unit Distribution Amount”), payable solely in common units, and (3) $0.09125 per Series A Preferred Unit per quarter (the “PIK Distribution Additional Amount”), payable solely in common units. The total number of common units payable in connection with the Common Unit Distribution Amount or the PIK Distribution Additional Amount cannot exceed $2 million in any period of 20 consecutive fiscal quarters.
Upon the Partnership’s breach of certain covenants (a “Covenant Default”), the holders of the Series A Preferred Units will be entitled to an increase of $0.1825 per quarterly distribution, payable solely in common units (the “Covenant Default Additional Amount”). All accumulated and unpaid distributions will accrue interest (i) at a rate of 2.432% per quarter, or (ii) if the Partnership has failed to pay all PIK Distribution Additional Amounts or Covenant Default Additional Amounts or any Covenant Default has occurred and is continuing, at a rate of 3.429% per quarter while such failure to pay or such Covenant Default continues.
The Series A Preferred Units are convertible, at the holder’s option, into common units, provided that the holder must request conversion of at least 375,000 Series A Preferred Units. The conversion price will initially be $18.30, subject to adjustment for customary events (such as unit splits). The number of common units issuable is equal to the issue price of the Series A Preferred Units (i.e. $18.30) being converted plus all accrued but unpaid distributions and accrued but unpaid interest thereon (the “Redeemable Face Amount”), divided by the applicable conversion price.
If at any time the volume-weighted average trading price of the common units over the trailing 20-trading day period (the “VWAP Price”) is less than the then-applicable conversion price, the conversion ratio is increased to: the quotient of (1) the Redeemable Face Amount on the date that the holder’s conversion notice is delivered, divided by (2) the product of (x) the VWAP Price set forth in the applicable conversion notice and (y) 91%, but will not be less than $10.
The Partnership has the right at any time to convert all or part of the Series A Preferred Units into common units, if (1) the daily volume-weighted average trading price of the common units is greater than 150% of the then-applicable conversion price for 20 out of the trailing 30 trading days, and (2) certain minimum public float and trading volume requirements are satisfied.
In the event of a change of control, the Partnership will be required to make an offer to the holders of the Series A Preferred Units to purchase their Series A Preferred Units for an amount equal to 101% of their Series A Liquidation Value. In addition, in the event of certain business combinations or other transactions involving the Partnership in which the holders of common units receive cash consideration exclusively in exchange for their common units (a “Cash Event”), the Partnership must use commercially reasonable efforts to ensure that the holders of the Series A Preferred Units will be entitled to receive a security issued by the surviving entity in the Cash Event with comparable powers, preferences and rights to the Series A Preferred Units. If the Partnership

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is unable to ensure that the holders of the Series A Preferred Units will be entitled to receive such a security, then the Partnership will be required to make an offer to the holders of the Series A Preferred Units to purchase their Series A Preferred Units for an amount equal to 120% of their Series A Liquidation Value. If the Partnership enters into any recapitalization, reorganization, consolidation, merger, spin-off that is not a Cash Event, the Partnership will make appropriate provisions to ensure that the holders of the Series A Preferred Units receive a security with comparable powers, preferences and rights to the Series A Preferred Units upon consummation of such transaction. Subsequent to the ETE Acquisition, no unitholder exercised this option.
As of December 31, 2014, the Series A Preferred Units were convertible to 2,064,805 common units.
The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the years ended December 31, 2014 and 2013:
 Units Amount 
Balance at January 1, 20134,371,586
 $73
  
Series A Preferred Units converted to common units(2,459,017) (41)  
Balance at January 1, 20141,912,569
 32
  
Accretion to redemption valueN/A
 1
  
Balance at December 31, 20141,912,569
 $33
*
* This amount will be accreted to $35 million plus any accrued but unpaid distributions and interest by deducting amounts from
partners’ capital over the remaining periods until the mandatory redemption date of September 2, 2029. Accretion during 2013
was immaterial.
14. RELATED PARTY TRANSACTIONS
As of December 31, 2014 and 2013, details of the Partnership’s related party receivables and related party payables were as follows:
 December 31,
 2014 2013
Related party receivables   
  ETE and its subsidiaries43
 25
  HPC1
 1
  Ranch JV1
 2
      Total related party receivables$45
 $28
    
Related party payables   
  ETE and its subsidiaries50
 68
  HPC3
 1
  Mi Vida JV11
 —
      Total related party payables$64
 $69
Transactions with ETE and its subsidiaries.Under the service agreement with Services Co., the Partnership paid Services Co.’s direct expenses for services performed, plus an annual fee of $10 million, and received the benefit of any cost savings recognized for these services. The services agreement has a five year term ending May 26, 2015, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default. On April 30, 2013, this agreement was amended to provide for a waiver of the $10 million annual fee effective as of May 1, 2013 through and including April 30, 2015 and to clarify the scope and expenses chargeable as direct expenses thereunder.
On April 30, 2013, the Partnership entered into the second amendment (the “Operation and Service Amendment”) to the Operation and Service Agreement (the “Operation and Service Agreement”), by and among the Partnership, ETC, the General Partner and RGS. Under the Operation and Service Agreement, ETC performs certain operations, maintenance and related services reasonably required to operate and maintain certain facilities owned by the Partnership, and the Partnership reimburses ETC for actual costs and expenses incurred in connection with the provision of these services based on an annual budget agreed upon by both parties.
The Partnership incurred total service fees related to the agreements described above from ETE and its subsidiaries of $6 million, $11 million and $17 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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In conjunction with distributions made by the Partnership to the limited and general partner interests, ETE and its subsidiaries received cash distributions of $175 million, $107 million and $62 million for the years ended December 31, 2014, 2013 and 2012, respectively.
The General Partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its general partner interest. No capital contributions were contributed during the years ended December 31, 2014 and 2013.
The Partnership’s Gathering and Processing segment, in the ordinary course of business, sells natural gas and NGLs to subsidiaries of ETE and records the revenue in gas sales and NGL sales. The Partnership’s Contract Services segment provides contract compression services to a subsidiary of ETE and records revenue in gathering, transportation and other fees on the statement of operations. As these transactions are between entities under common control, partners’ capital was increased, which represented a deemed contribution of the excess sales price over the carrying amounts. The Partnership’s Gathering and Processing segment recorded revenues from subsidiaries of ETE of $351 million and cost of sales to subsidiaries of ETE of $52 million for the year ended December 31, 2014. The Partnership’s Contract Services segment recorded revenues from a subsidiary of ETE of $1 million for the year ended December 31, 2014. The Partnership’s Contract Services segment purchased $67 million and $95 million of compression equipment from a subsidiary of ETE during the years ended December 31, 2014 and 2013, respectively.
Prior to April 30, 2013, Southern Union provided certain administrative services for SUGS that were either based on SUGS’s pro-rata share of combined net investment, margin and certain expenses or direct costs incurred by Southern Union on the behalf of SUGS. Southern Union also charged a management and royalty fee to SUGS for certain management support services provided by Southern Union on the behalf of SUGS and for the use of certain Southern Union trademarks, trade names and service marks by SUGS. The amounts were $21 million and $1 million for the period from March 26, 2012 to December 31, 2012. These administrative services were no longer being provided subsequent to the SUGS Acquisition.
Transactions with Lone Star. The Partnership entered into various agreements to sell NGLs to Lone Star. For the year ended December 31, 2014, the Partnership had recorded $257 million in NGL sales under these contracts.
Transactions with HPC. Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. For the years ended December 31, 2014, 2013, and 2012, the related party general and administrative expenses reimbursed to the Partnership were $14 million, $18 million, and $20 million, respectively, which is recorded in gathering, transportation and other fees.
The Partnership’s Contract Services segment provides compression services to HPC and records revenue in gathering, transportation and other fees. The Partnership also receives transportation services from HPC and records it as cost of sales.
15. CONCENTRATION RISK
The following table provides information about the extent of reliance on major customers and gas suppliers. Total revenues and cost of sales from transactions with an external customer or supplier amounting to 10% or more of revenue or cost of gas and liquids are disclosed below, together with the identity of the reportable segment.
   Years Ended December 31,
 Reportable Segment 2014 2013 2012
Customer       
   Customer AGathering and Processing $—
 $381
 $367
   Customer BGathering and Processing 780
 362
 451
Supplier       
   Supplier AGathering and Processing —
 164
 171
   Supplier BGathering and Processing —
 185
 —
The Partnership is a party to various commercial netting agreements that allow it and contractual counterparties to net receivable and payable obligations. These agreements are customary and the terms follow standard industry practice. In the opinion of management, these agreements reduce the overall counterparty risk exposure.

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16. SEGMENT INFORMATION
The Partnership has six reportable segments: Gathering and Processing, Natural Gas Transportation, NGL Services, Contract Services, Natural Resources and Corporate. The reportable segments are as described below:
Gathering and Processing. The Partnership provides “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs from the raw natural gas and selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, the gathering of oil (crude and/or condensate, a lighter oil) received from producers, the gathering and disposing of salt water, and natural gas and NGL marketing and trading. This segment also includes the Partnership’s 60% membership interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, the Partnership’s 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL-rich shale formations in west Texas, the Partnership’s 50% interest in Sweeny JV, which operates a natural gas gathering facility in south Texas, the Partnership’s 51% membership interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, the Partnership’s 75% membership interest in ORS, which will operate a natural gas gathering system in the Utica shale in Ohio, and the Partnership’s 50% interest in Mi Vida JV, which will operate a cryogenic processing plant and related facilities in west Texas.
Natural Gas Transportation. The Partnership owns a 49.99% general partner interest in HPC, which owns RIGS, a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in MEP, which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama.  This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
NGL Services. The Partnership owns a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including NGL pipelines, storage, fractionation and processing facilities located in Texas, New Mexico, Mississippi and Louisiana.
Contract Services. The Partnership owns and operates a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. The Partnership also owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management.
Natural Resources. The Partnership is involved in the management of coal and natural resources properties and the related collection of royalties. The Partnership also earns revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment also included the Partnership’s 50%interest in Coal Handling, which owns and operates end-user coal handling facilities. The Partnership purchased the remaining 50% interest in these companies effective December 31, 2014.
Corporate. The Corporate segment comprises the Partnership’s corporate assets.
The Partnership accounts for intersegment revenues as if the revenues were to third parties, exclusive of certain cost of capital charges.
Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses. Segment margin, for the Gathering and Processing and the Natural Gas Transportation segments is defined as total revenues, including service fees, less cost of sales. In the Contract Services segment, segment margin is defined as revenues less direct costs. The Natural Resources segment margin is generally equal to total revenues
as there is typically minimal cost of sales associated with the management and leasing of properties.
Management believes segment margin is an important measure because it directly relates to volume, commodity price changes, and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period. The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin. The Partnership does not record segment margin for its investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua - PVR, Mi Vida JV and Sweeny JV) because it records its ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting.

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Results for each period, together with amounts related to each segment are shown below:
 Years Ended December 31,
 2014 2013 2012
External Revenue     
Gathering and Processing$4,570
 $2,287
 $1,797
Natural Gas Transportation—
 1
 1
NGL Services—
 —
 —
Contract Services307
 215
 183
Natural Resources58
 —
 —
Corporate16
 18
 19
Eliminations—
 —
 —
Total$4,951
 $2,521
 $2,000
      
Intersegment Revenue     
Gathering and Processing$—
 $—
 $—
Natural Gas Transportation—
 —
 —
NGL Services—
 —
 —
Contract Services14
 15
 21
Natural Resources—
 —
 —
Corporate—
 —
 —
Eliminations(14) (15) (21)
Total$—
 $—
 $—
      
Cost of Sales     
Gathering and Processing$3,381
 $1,767
 $1,373
Natural Gas Transportation—
 —
 (1)
NGL Services—
 —
 —
Contract Services67
 26
 15
Natural Resources—
 —
 —
Corporate4
 —
 —
Eliminations—
 —
 —
Total$3,452
 $1,793
 $1,387
      
Segment Margin     
Gathering and Processing$1,189
 $520
 $423
Natural Gas Transportation—
 1
 2
NGL Services—
 —
 —
Contract Services254
 204
 189
Natural Resources58
 —
 —
Corporate12
 18
 20
Eliminations(14) (15) (21)
Total$1,499
 $728

$613
      

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 Years Ended December 31,
 2014 2013 2012
Operation and Maintenance     
Gathering and Processing$360
 $237
 $183
Natural Gas Transportation—
 —
 —
NGL Services—
 —
 —
Contract Services86
 72
 66
Natural Resources12
 —
 —
Corporate3
 1
 —
Eliminations(13) (14) (21)
Total$448
 $296
 $228
      
Depreciation, Depletion and Amortization     
Gathering and Processing$385
 $186
 $159
Natural Gas Transportation—
 —
 —
NGL Services—
 —
 —
Contract Services134
 98
 86
Natural Resources14
 —
 —
Corporate8
 3
 7
Eliminations—
 —
 —
Total$541
 $287
 $252
Income from Unconsolidated Affiliates     
Gathering and Processing$5
 $1
 $(10)
Natural Gas Transportation72
 70
 71
NGL Services116
 64
 44
Contract Services—
 —
 —
Natural Resources2
 —
 —
Corporate—
 —
 —
Eliminations—
 —
 —
Total$195
 $135
 $105
      
Expenditures for Long-Lived Assets     
Gathering and Processing$700
 $721
 $395
Natural Gas Transportation—
 —
 —
NGL Services—
 —
 —
Contract Services371
 311
 164
Natural Resources—
 —
 —
Corporate17
 2
 1
Eliminations—
 —
 —
Total$1,088
 $1,034
 $560



S - 116

 December 31,
 2014 2013 2012
Assets     
Gathering and Processing$12,069
 $4,748
 $4,210
Natural Gas Transportation1,119
 991
 1,232
NGL Services1,162
 1,070
 948
Contract Services2,035
 1,897
 1,672
Natural Resources529
 —
 —
Corporate189
 76
 61
Eliminations—
 —
 —
Total$17,103
 $8,782
 $8,123
      
Investments in Unconsolidated Affiliates     
Gathering and Processing$139
 $36
 $35
Natural Gas Transportation1,117
 991
 1,231
NGL Services1,162
 1,070
 948
Contract Services—
 —
 —
Natural Resources—
 —
 —
Corporate—
 —
 —
Eliminations—
 —
 —
Total$2,418
 $2,097
 $2,214
      
Goodwill     
Gathering and Processing (1)
$732
 $651
 $651
Natural Gas Transportation—
 —
 —
NGL Services—
 —
 —
Contract Services476
 477
 477
Natural Resources15
 —
 —
Corporate—
 —
 —
Eliminations—
 —
 —
Total$1,223
 $1,128
 $1,128

(1) In 2014, the Partnership recorded a $370 million impairment charge at the Permian reporting unit within this segment.

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The table below provides a reconciliation of total segment margin to (loss) income before income taxes:
 Years Ended December 31,
 2014 2013 2012 
Total segment margin$1,499
 $728
 $613
 
Operation and maintenance(448) (296) (228) 
General and administrative(158) (88) (100) 
Gain (loss) on assets sales, net1
 (2) (3) 
Depreciation, depletion and amortization(541) (287) (252) 
Goodwill impairment(370) —
 —
 
Income from unconsolidated affiliates195
 135
 105
 
Interest expense, net(304) (164) (122) 
Loss on debt refinancing, net(25) (7) (8) 
Other income and deductions, net12
 7
 29
*
(Loss) income before income taxes$(139) $26
 $34
 
__________________
*
Other income and deductions, net for the year ended December 31, 2012, included a one-time producer payment of $16 million related to an assignment of certain contracts.
17. EQUITY-BASED COMPENSATION
In December 2011, the Partnership’s unitholders approved the Regency Energy Partners LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”), which provides for awards of options to purchase the Partnership’s common units; awards of the Partnership’s restricted units, phantom units and common units; awards of distribution equivalent rights; awards of common unit appreciation rights; and other unit-based awards to employees, directors and consultants of the Partnership and its affiliates and subsidiaries. The 2011 Incentive Plan will be administered by the Compensation Committee of the board of directors, which may, in its sole discretion, delegate its powers and duties under the 2011 Incentive Plan to the Chief Executive Officer. Up to 3,000,000 of the Partnership’s common units may be granted as awards under the 2011 Incentive Plan, with such amount subject to adjustment as provided for under the terms of the 2011 Incentive Plan.
The 2011 Incentive Plan may be amended or terminated at any time by the board of directors or the Compensation Committee without the consent of any participant or unitholder, including an amendment to increase the number of common units available for awards under the plan; however, any material amendment, such as a change in the types of awards available under the plan, would require the approval of the unitholders of the Partnership. The Compensation Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the 2011 Incentive Plan in specified circumstances. The 2011 Incentive Plan is effective until December 19, 2021 or, if earlier, the time at which all available units under the 2011 Incentive Plan have been issued to participants or the time of termination of the plan by the board of directors.
Unit-based compensation expense of $10 million, $7 million, and $5 million is recorded in general and administrative expense in the statement of operations for the years ended December 31, 2014, 2013 and 2012, respectively.
Common Unit Options. The fair value of each option award is estimated on the date of grant using the Black-Scholes Option Pricing Model. Upon the exercise of the common unit options, the Partnership intends to settle these obligations with new issues of common units on a net basis. The common unit options activity for the year ended December 31, 2014 is as follows:
Common Unit Options Units Weighted Average Exercise Price
Outstanding at the beginning of period 142,550
 $22.04
Exercised (34,900) 20.03
Outstanding at end of period 107,650
 22.68
Exercisable at the end of the period 107,650
  
The common unit options have an intrinsic value of less than $1 million related to non-vested units with a weighted average contractual term of 1.5 years. Intrinsic value is the closing market price of a common unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented. Unit options with an exercise price greater than the end of the period closing market price are excluded.

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Phantom Units. During 2014, the Partnership awarded 1,450,230 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that vest 60% after the third year of continued employment and 40% after the fifth year of continued employment. Distributions on the phantom units will be paid concurrent with the Partnership’s distribution for common units.
During 2013, the Partnership awarded 62,360 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that generally vest 60% after the third year of continued employment and 40% after the fifth year of continued employment. Distributions on the phantom units will be paid concurrent with the Partnership’s distribution for common units.
In December 2012, the Partnership awarded 495,375 phantom units to senior management and certain key employees. These awards are service condition (time-based) grants that vest 60% after the third year of continued employment and 40% after the fifth year of continued employment. Also during 2012, 8,250 phantom units were awarded to senior management and key employees as service condition (time-based) grants that generally vest ratably over a 5 year period. Distributions on the phantom units will be paid concurrent with the Partnership’s distribution for common units.
The following table presents phantom unit activity for the year ended December 31, 2014:
Phantom Units Units 
Weighted Average
Grant Date
Fair Value
Outstanding at the beginning of the period 982,242
 $23.16
Service condition grants 1,450,230
 25.24
Vested service condition (183,380) 25.25
Forfeited service condition (81,373) 24.83
Total outstanding at end of period 2,167,719
 24.31

During the years ended December 31, 2014, 2013 and 2012, the weighted average grant date fair value per phantom unit granted was $25.24, $25.44, and $21.39, respectively. The total fair value of awards vested was $5 million, $6 million, and $5 million for the years ended December 31, 2014, 2013 and 2012, respectively, based on the market price of Regency common units as of the vesting date.

The Partnership expects to recognize $42 million of unit-based compensation expense related to non-vested phantom units over a period of 3.9 years.

Cash Restricted Units. The Partnership began granting cash restricted units in 2014. These awards are service condition (time-based) grants of notional units that vest 100% after the third year of continued employment. A cash restricted unit entitles the award recipient to receive cash equal to the market price of one Regency common unit as of the vesting date.

The following table presents cash restricted unit activity for the year ended December 31, 2014:
Cash Restricted UnitsUnits
Outstanding at the beginning of the period—
Service condition grants400,928
Vested service condition(500)
Forfeited service condition(21,100)
Total outstanding at end of period379,328

Based on the trading price of Regency common units at December 31, 2014, the Partnership expects to recognize $7 million of unit-based compensation expense related to non-vested cash restricted units over a period of 2.5 years.
18. CONSOLIDATING GUARANTOR FINANCIAL INFORMATION
ELG, Aqua - PVR, and ORS do not fully and unconditionally guarantee, on a joint and several basis, the Senior Notes issued and outstanding as of December 31, 2014, by the Partnership and Finance Corp. Included in the Parent financial statements are the Partnership’s intercompany investments in all consolidated subsidiaries and the Partnership’s investments in unconsolidated affiliates. ELG, Aqua - PVR, and ORS are included in the non-guarantor subsidiaries.

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The consolidating financial information for the Parent Guarantor, Subsidiaries,Subsidiary Issuer and Non GuarantorNon-Guarantor Subsidiaries are as follows:
 December 31, 2014
 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
ASSETS         
Cash$—
 $—
 $32
 $(8) $24
All other current assets—
 667
 13
 (1) 679
Property, plant, and equipment, net—
 8,948
 353
 (84) 9,217
Investments in subsidiaries19,829
 —
 —
 (19,829) —
Investments in unconsolidated affiliates—
 2,252
 —
 166
 2,418
All other assets—
 4,765
 —
 —
 4,765
TOTAL ASSETS$19,829
 $16,632
 $398
 $(19,756) $17,103
          
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST         
All other current liabilities—
 723
 34
 (1) 756
Long-term liabilities5,185
 1,575
 6
 (4) 6,762
Noncontrolling interest—
 —
 —
 120
 120
Total partners’ capital and noncontrolling interest14,644
 14,334
 358
 (19,871) 9,465
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST$19,829
 $16,632
 $398
 $(19,756) $17,103
 December 31, 2017
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash and cash equivalents$—
 $(3) $309
 $—
 $306
All other current assets—
 159
 6,063
 —
 6,222
Property, plant and equipment—
 —
 58,437
 —
 58,437
Investments in unconsolidated affiliates48,378
 11,648
 3,816
 (60,026) 3,816
All other assets—
 —
 9,184
 —
 9,184
Total assets$48,378
 $11,804
 $77,809
 $(60,026) $77,965
          
Current liabilities(1,496) (3,660) 12,150
 —
 6,994
Non-current liabilities21,604
 7,607
 7,609
 —
 36,820
Noncontrolling interest—
 —
 5,882
 —
 5,882
Total partners’ capital28,270
 7,857
 52,168
 (60,026) 28,269
Total liabilities and equity$48,378
 $11,804
 $77,809
 $(60,026) $77,965
 December 31, 2016
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash and cash equivalents$—
 $41
 $319
 $—
 $360
All other current assets—
 2
 5,281
 —
 5,283
Property, plant and equipment—
 —
 50,917
 —
 50,917
Investments in unconsolidated affiliates23,350
 10,664
 4,280
 (34,014) 4,280
All other assets—
 5
 9,260
 —
 9,265
Total assets$23,350
 $10,712
 $70,057
 $(34,014) $70,105
          
Current liabilities(1,761) (3,800) 11,764
 —
 6,203
Non-current liabilities299
 7,313
 30,148
 (299) 37,461
Noncontrolling interest—
 —
 1,232
 —
 1,232
Total partners’ capital24,812
 7,199
 26,913
 (33,715) 25,209
Total liabilities and equity$23,350
 $10,712
 $70,057
 $(34,014) $70,105

 December 31, 2013
 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
ASSETS         
Cash$—
 $—
 $19
 $—
 $19
All other current assets—
 366
 15
 —
 381
Property, plant, and equipment, net—
 4,244
 174
 —
 4,418
Investments in subsidiaries10,446
 —
 —
 (10,446) —
Investments in unconsolidated affiliates—
 1,995
 —
 102
 2,097
All other assets—
 1,867
 —
 —
 1,867
TOTAL ASSETS$10,446
 $8,472
 $208
 $(10,344) $8,782
          
LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST         
All other current liabilities—
 466
 9
 —
 475
Long-term liabilities2,832
 559
 —
 —
 3,391
Noncontrolling interest—
 —
 —
 102
 102
Total partners’ capital and noncontrolling interest7,614
 7,447
 199
 (10,446) 4,814
TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST$10,446
 $8,472
 $208
 $(10,344) $8,782


S - 120

 For the year ended December 31, 2014
 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$—
 $4,888
 $66
 $(3) $4,951
Operating costs, expenses, and other—
 4,942
 35
 (9) 4,968
Operating (loss) income—
 (54) 31
 6
 (17)
Income from unconsolidated affiliates—
 195
 —
 —
 195
Interest expense, net(290) (14) —
 —
 (304)
Loss on debt refinancing, net(24) (1) —
 —
 (25)
Equity in consolidated subsidiaries166
 —
 —
 (166) —
Other income and deductions, net3
 9
 —
 —
 12
(Loss) income before income taxes(145) 135
 31
 (160) (139)
Income tax expense (benefit)4
 (2) 1
 —
 3
Net (loss) income(149) 137
 30
 (160) (142)
Net income attributable to noncontrolling interest—
 —
 —
 (15) (15)
Net (loss) income attributable to Regency Energy Partners LP$(149) $137
 $30
 $(175) $(157)
          
Total other comprehensive income$—
 $—
 $—
 $—
 $—
Comprehensive (loss) income(149) 137
 30
 (160) (142)
Comprehensive income attributable to noncontrolling interest—
 —
 —
 15
 15
Comprehensive (loss) income attributable to Regency Energy Partners LP$(149) $137
 $30
 $(175) $(157)


S - 121

 For the year ended December 31, 2013
 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$—
 $2,489
 $32
 $—
 $2,521
Operating costs, expenses, and other3
 2,448
 15
 —
 2,466
Operating (loss) income(3) 41
 17
 —
 55
Income from unconsolidated affiliates—
 135
 —
 —
 135
Interest expense, net(148) (16) —
 —
 (164)
Loss on debt refinancing, net(7) —
 —
 —
 (7)
Equity in consolidated subsidiaries172
 —
 —
 (172) —
Other income and deductions, net7
 —
 —
 —
 7
Income before income taxes21
 160
 17
 (172) 26
Income tax expense (benefit)1
 (2) —
 —
 (1)
Net income20
 162
 17
 (172) 27
Net income attributable to noncontrolling interest—
 (8) —
 —
 (8)
Net income attributable to Regency Energy Partners LP$20
 $154
 $17
 $(172) $19
          
Total other comprehensive income$—
 $—
 $—
 $—
 $—
Comprehensive income20
 162
 17
 (172) 27
Comprehensive income attributable to noncontrolling interest—
 8
 —
 —
 8
Comprehensive income attributable to Regency Energy Partners LP$20
 $154
 $17
 $(172) $19


S - 122

 For the year ended December 31, 2012
 Parent��Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$—
 $1,985
 $15
 $—
 $2,000
Operating costs, expenses, and other10
 1,951
 9
 —
 1,970
Operating (loss) income(10) 34
 6
 —
 30
Income from unconsolidated affiliates—
 105
 —
 —
 105
Interest expense, net(104) (18) —
 —
 (122)
Gain (loss) on debt refinancing, net(8) —
 —
 —
 (8)
Equity in consolidated subsidiaries141
 —
 —
 (141) —
Other income and deductions, net14
 15
 —
 —
 29
Income before income taxes33
 136
 6
 (141) 34
Income tax expense (benefit)1
 (1) —
 —
 —
Net income32
 137
 6
 (141) 34
Net income attributable to noncontrolling interest—
 (2) —
 —
 (2)
Net income attributable to Regency Energy Partners LP$32
 $135
 $6
 $(141) $32
          
Total other comprehensive income (loss)$—
 $2
 $—
 $—
 $2
Comprehensive income32
 139
 6
 (141) 36
Comprehensive income attributable to noncontrolling interest—
 2
 —
 —
 2
Comprehensive income attributable to Regency Energy Partners LP$32
 $137
 $6
 $(141) $34
 Year Ended December 31, 2017
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$—
 $—
 $29,054
 $—
 $29,054
Operating costs, expenses, and other—
 1
 26,656
 —
 26,657
Operating income (loss)—
 (1) 2,398
 —
 2,397
Interest expense, net—
 (156) (1,209) —
 (1,365)
Equity in earnings of unconsolidated affiliates2,564
 1,242
 156
 (3,806) 156
Impairment of investments in unconsolidated affiliate—
 —
 (313) —
 (313)
Losses on interest rate derivatives—
 —
 (37) —
 (37)
Other, net—
 —
 168
 (1) 167
Income before income tax benefit2,564
 1,085
 1,163
 (3,807) 1,005
Income tax benefit—
 —
 (1,496) —
 (1,496)
Net income2,564
 1,085
 2,659
 (3,807) 2,501
Less: Net income attributable to noncontrolling interest—
 —
 420
 —
 420
Net income attributable to partners$2,564
 $1,085
 $2,239
 $(3,807) $2,081
          
Other comprehensive income (loss)$—
 $—
 $(5) $—
 $(5)
Comprehensive income2,564
 1,085
 2,654
 (3,807) 2,496
Comprehensive income attributable to noncontrolling interest—
 —
 420
 —
 420
Comprehensive income attributable to partners$2,564
 $1,085
 $2,234
 $(3,807) $2,076

 For the year ended December 31, 2014
 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows from operating activities$—
 $664
 $56
 $(1) $719
Cash flows from investing activities—
 (2,130) (30) (9) (2,169)
Cash flows from financing activities—
 1,466
 (13) 2
 1,455
Change in cash—
 —
 13
 (8) 5
Cash at beginning of period—
 —
 19
 —
 19
Cash at end of period$—
 $—
 $32
 $(8) $24
 Year Ended December 31, 2016
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$—
 $—
 $21,827
 $—
 $21,827
Operating costs, expenses, and other—
 1
 20,065
 —
 20,066
Operating income (loss)—
 (1) 1,762
 —
 1,761
Interest expense, net—
 (157) (1,160) —
 (1,317)
Equity in earnings of unconsolidated affiliates554
 863
 59
 (1,417) 59
Impairment of investment in unconsolidated affiliate—
 —
 (308) —
 (308)
Losses on interest rate derivatives—
 —
 (12) —
 (12)
Other, net—
 —
 214
 —
 214
Income before income tax benefit554
 705
 555
 (1,417) 397
Income tax benefit—
 —
 (186) —
 (186)
Net income554
 705
 741
 (1,417) 583
Less: Net income attributable to noncontrolling interest—
 —
 41
 —
 41
Net income attributable to partners$554
 $705
 $700
 $(1,417) $542
          
Other comprehensive income$—
 $—
 $4
 $—
 $4
Comprehensive income554
 705
 745
 (1,417) 587
Comprehensive income attributable to noncontrolling interest—
 —
 41
 —
 41
Comprehensive income attributable to partners$554
 $705
 $704
 $(1,417) $546


 For the year ended December 31, 2013
 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows from operating activities$—
 $424
 $12
 $—
 $436
Cash flows from investing activities—
 (1,303) (90) —
 (1,393)
Cash flows from financing activities—
 879
 44
 —
 923
Change in cash—
 —
 (34) —
 (34)
Cash at beginning of period—
 —
 53
 —
 53
Cash at end of period$—
 $—
 $19
 $—
 $19
 Year Ended December 31, 2015
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Revenues$—
 $—
 $34,292
 $—
 $34,292
Operating costs, expenses, and other—
 1
 32,064
 —
 32,065
Operating income (loss)—
 (1) 2,228
 —
 2,227
Interest expense, net—
 (133) (1,158) —
 (1,291)
Equity in earnings of unconsolidated affiliates1,441
 526
 469
 (1,967) 469
Losses on interest rate derivatives—
 —
 (18) —
 (18)
Other, net—
 —
 (21) —
 (21)
Income before income tax benefit1,441
 392
 1,500
 (1,967) 1,366
Income tax benefit—
 —
 (123) —
 (123)
Net income1,441
 392
 1,623
 (1,967) 1,489
Less: Net income attributable to noncontrolling interest—
 —
 53
 —
 53
Net income attributable to partners$1,441
 $392
 $1,570
 $(1,967) $1,436
          
Other comprehensive income$—
 $—
 $60
 $—
 $60
Comprehensive income1,441
 392
 1,683
 (1,967) 1,549
Comprehensive income attributable to noncontrolling interest—
 —
 53
 —
 53
Comprehensive income attributable to partners$1,441
 $392
 $1,630
 $(1,967) $1,496
 Year Ended December 31, 2017
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows from operating activities$2,564
 $1,047
 $4,681
 $(3,807) $4,485
Cash flows from investing activities(2,240) (1,368) (5,672) 3,807
 (5,473)
Cash flows from financing activities(324) 277
 981
 —
 934
Change in cash—
 (44) (10) —
 (54)
Cash at beginning of period—
 41
 319
 —
 360
Cash at end of period$—
 $(3) $309
 $—
 $306
 Year Ended December 31, 2016
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows from operating activities$553
 $675
 $3,492
 $(1,417) $3,303
Cash flows from investing activities(976) (2,400) (4,431) 1,417
 (6,390)
Cash flows from financing activities423
 1,729
 768
 —
 2,920
Change in cash—
 4
 (171) —
 (167)
Cash at beginning of period—
 37
 490
 —
 527
Cash at end of period$—
 $41
 $319
 $—
 $360

 Year Ended December 31, 2015
 Parent Guarantor Subsidiary Issuer Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows from operating activities$1,441
 $388
 $2,886
 $(1,968) $2,747
Cash flows from investing activities(2,271) (1,815) (5,702) 1,968
 (7,820)
Cash flows from financing activities830
 1,363
 2,744
 —
 4,937
Change in cash—
 (64) (72) —
 (136)
Cash at beginning of period—
 101
 562
 —
 663
Cash at end of period$—
 $37
 $490
 $—
 $527





S - 12376

 For the year ended December 31, 2012
 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Partnership
Cash flows from operating activities$—
 $316
 $8
 $—
 $324
Cash flows from investing activities—
 (746) (61) —
 (807)
Cash flows from financing activities—
 430
 105
 —
 535
Change in cash—
 —
 52
 —
 52
Cash at beginning of period—
 —
 1
 —
 1
Cash at end of period$—
 $—
 $53
 $—
 $53

19. QUARTERLY FINANCIAL DATA (UNAUDITED)
  Quarter Ended
2014 December 31 September 30 June 30 March 31
Operating revenues $1,427
 $1,483
 $1,178
 $863
Operating (loss) income (218) 144
 35
 22
Net (loss) income attributable to Regency Energy Partners LP (261) 103
 (8) 9
Earnings per common units:        
Basic net (loss) income per common unit (0.67) 0.23
 (0.05) 0.00
Diluted net (loss) income per common unit (0.67) 0.23
 (0.05) 0.00
         
  Quarter Ended
2013 December 31 September 30 June 30 March 31
Operating revenues $677
 $665
 $639
 $540
Operating income (loss) 12
 24
 34
 (15)
Net (loss) income attributable to Regency Energy Partners LP (1) 39
 10
 (29)
Earnings per common units:        
Basic net (loss) income per common unit (0.03) 0.16
 0.07
 (0.06)
Diluted net (loss) income per common unit (0.03) 0.05
 0.07
 (0.06)
The three months ended December 31, 2014 includes a $370 million goodwill impairment charge recorded related to the Permian reporting unit within the Gathering and Processing segment.


S - 124