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ET Energy Transfer

Filed: 21 Feb 20, 1:47pm
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
ENERGY TRANSFER LP
(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.)
8111 Westchester Drive, Suite 600, Dallas, Texas 75225
(Address of principal executive offices) (zip code)
(214981-0700
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
Common Units ET 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 every Interactive Data File required to be submitted 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 such files).
Yes  ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “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, 2019, 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 $30.57 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 14, 2020, the registrant had 2,689,897,793 Common Units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None



TABLE OF CONTENTS
 
 


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Forward-Looking Statements
Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer LP (the “Partnership” or “ET”) 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 used throughout this document: 
/d  per day
   
AOCI accumulated other comprehensive income (loss)
   
AROs asset retirement obligations
   
Bbls  barrels
  
BBtu billion 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
   
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
   
CDM CDM Resource Management LLC and CDM Environmental & Technical Services LLC, collectively
   
Citrus Citrus, LLC
   
Dakota Access Dakota Access, LLC, a less than wholly-owned subsidiary of ETO
   
DOE United States Department of Energy
   
DOJ United States Department of Justice
   
DOT United States Department of Transportation
   
EPA United States Environmental Protection Agency
   
ETC OLP La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company and is a wholly-owned subsidiary of ETO
   
ETC Sunoco ETC Sunoco Holdings LLC (formerly, Sunoco Inc.), a wholly-owned subsidiary of ETO
   
ETC Tiger ETC Tiger Pipeline, LLC, a wholly-owned subsidiary of ETO
   
ETCO Energy Transfer Crude Oil Company, LLC
   
ETO Energy Transfer Operating, L.P., formerly known as Energy Transfer Partners, L.P.
   
ETO Preferred Unitholders Unitholders of the ETO Series A Preferred Units, ETO Series B Preferred Units, ETO Series D Preferred Units, ETO Series E Preferred Units, ETO Series F Preferred Units and ETO Series G Preferred Units, collectively
   
ETO Series A Preferred Units Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

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ETO Series B Preferred Units Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
   
ETO Series C Preferred Units Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
   
ETO Series D Preferred Units Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
   
ETO Series E Preferred Units Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
   
ETO Series F Preferred Units Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
   
ETO Series G Preferred Units Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
   
ETP GP Energy Transfer Partners GP, L.P., the general partner of ETO
   
ETP Holdco ETP Holdco Corporation, a wholly-owned subsidiary of ETO
   
ETP LLC Energy Transfer Partners, L.L.C., the general partner of ETP GP
   
Exchange Act Securities Exchange Act of 1934, as amended
   
ExxonMobil Exxon Mobil Corporation
   
FEP Fayetteville Express Pipeline LLC
   
FERC Federal Energy Regulatory Commission
   
FGT Florida Gas Transmission Company, LLC, a wholly-owned subsidiary of Citrus
   
GAAP accounting principles generally accepted in the United States of America
   
Gulf States Gulf States Transmission LLC, a wholly-owned subsidiary of ETO
   
General Partner LE GP, LLC, the general partner of ET
   
HFOTCO Houston Fuel Oil Terminal Company, a wholly-owned subsidiary of ETO, which owns the Houston Terminal
   
HPC RIGS Haynesville Partnership Co., a wholly-owned subsidiary of ETO
   
IDRs incentive distribution rights
   
KMI Kinder Morgan Inc.
   
Lake Charles LNG Lake Charles LNG Company, LLC (previously named Trunkline LNG Company, LLC), a wholly-owned subsidiary of ETO
   
LCL Lake Charles LNG Export Company, LLC, a wholly-owned subsidiary of ETO
   
LIBOR London Interbank Offered Rate
   
LNG liquefied natural gas
   
Lone Star Lone Star NGL LLC, a wholly-owned subsidiary of ETO
   
MBbls thousand barrels
   
MMBbls millions barrels
   
MEP Midcontinent Express Pipeline LLC
   
Mi Vida JV Mi Vida JV LLC
   
Mid-Valley Mid-Valley Pipeline Company, a wholly-owned subsidiary of ETO
   
MMBbls  million barrels
   
MMcf million cubic feet
   

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MTBE methyl tertiary butyl ether
   
NGL  natural gas liquid, such as propane, butane and natural gasoline
   
NYMEX  New York Mercantile Exchange
  
NYSE New York Stock Exchange
   
ORS Ohio River System LLC, a less than wholly-owned subsidiary of ETO
   
OSHA Federal Occupational Safety and Health Act
   
OTC over-the-counter
  
Panhandle Panhandle Eastern Pipe Line Company, LP and its subsidiaries, wholly-owned by ETO
   
PCBs polychlorinated biphenyls
   
PennTex PennTex Midstream Partners, LP
   
PEP Permian Express Partners LLC, a less than wholly-owned subsidiary of ETO
   
PES Philadelphia Energy Solutions Refining and Marketing LLC
   
Phillips 66 Phillips 66 Partners LP
   
PHMSA Pipeline Hazardous Materials Safety Administration
   
Ranch JV Ranch Westex JV LLC
   
Regency Regency Energy Partners LP, a wholly-owned subsidiary of ETO
   
Retail Holdings ETP Retail Holdings LLC, a wholly-owned subsidiary of ETO
   
RIGS Regency Intrastate Gas System, a wholly-owned subsidiary of ETO
  
Rover Rover Pipeline LLC, a less than wholly-owned subsidiary of ETO
   
Sea Robin Sea Robin Pipeline Company, LLC, a wholly-owned subsidiary of Panhandle
   
SEC Securities and Exchange Commission
   
SemCAMS SemCAMS Midstream ULC, a less than wholly-owned subsidiary of ET
   
SemGroup SemGroup Corporation
   
Shell Royal Dutch Shell plc
   
Southwest Gas Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage Company)
   
SPLP Sunoco Pipeline L.P., a wholly-owned subsidiary of ETO
   
   
Sunoco Logistics Sunoco Logistics Partners L.P., a wholly-owned subsidiary of ETO
   
Sunoco (R&M) Sunoco (R&M), LLC
   
Transwestern Transwestern Pipeline Company, LLC, a wholly-owned subsidiary of ETO
   
TRRC Texas Railroad Commission
   
Trunkline Trunkline Gas Company, LLC, a wholly-owned subsidiary of Panhandle
   
USAC USA Compression Partners, LP, a wholly-owned subsidiary of ETO
   
WMB The Williams Companies, Inc.
Adjusted EBITDA is a term used throughout this document, which we define as total Partnership 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, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion,

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amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.  The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.

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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 “ET.”
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ET” mean Energy Transfer LP and its consolidated subsidiaries, which include ETO, ETP GP, ETP LLC, Panhandle, Sunoco LP, USAC, SemGroup and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.
The primary activities in which we are engaged, which are in the United States and Canada, and the operating subsidiaries through which we conduct those activities are as follows:
natural gas operations, including the following:
natural gas midstream and intrastate transportation and storage;
interstate natural gas transportation and storage; and
crude oil, NGL and refined products transportation, terminalling services and acquisition and marketing activities, as well as NGL storage and fractionation services.
In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are publicly traded master limited partnerships.
Substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses, debt service requirements and distributions to its partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of its subsidiaries. The Parent Company distributes its available cash remaining after satisfaction of the 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.

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The following chart summarizes our organizational structure as of February 14, 2020. For simplicity, certain immaterial entities and ownership interests have not been depicted.
orgchartfinala02.jpg

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Unless the context requires otherwise, the Partnership and its subsidiaries are collectively referred to in this report as “we,” “us,” “ET,” “Energy Transfer” or “the Partnership.”
Significant Achievements in 2019 and Beyond
Strategic Transactions Related to the Partnership
In December 2019, ET completed its acquisition of Tulsa-based SemGroup Corporation in a unit and cash transaction, and during the first quarter of 2020, certain of the operating assets of SemGroup were contributed to ETO. The segment and asset overviews below include the SemGroup assets.
Significant Organic Growth Projects
Our significant announced organic growth projects in 2019 included the following, as discussed in more detail herein:
In December 2019, ET announced a comprehensive commercial tender package which was issued to engineering, procurement and construction contractors to submit final bids for the proposed Lake Charles LNG liquefaction project being developed with Shell US LNG, LLC. The project would modify ETO’s existing LNG import facility located in Lake Charles, Louisiana to add LNG liquefaction capacity of 16.45 million tonnes per annum for expert to global markets. The commercial bids are expected to be received in the second quarter of 2020.
In connection with the acquisition of SemGroup and to provide shippers with further access to markets along the Gulf Coast through the Houston Ship Channel, ET announced the construction of the Ted Collins pipeline, a 75-mile crude line that will connect Houston Terminal, which was recently acquired in the SemGroup acquisition, to the Nederland terminal. The pipeline is expected to be in service in 2021 and will have an initial capacity of 500 MBbls/d.
Segment Overview
See Note 17 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our segments.
Intrastate Transportation and Storage Segment
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, power generators and other third-party pipelines. Through our intrastate transportation and storage segment, we own and operate (through wholly-owned or through joint venture interests) approximately 9,400 miles of natural gas transportation pipelines with approximately 22 Bcf/d of transportation capacity and three natural gas storage facilities located in the state of Texas.
We own a 70% interest in the Red Bluff Express Pipeline, a 108-mile intrastate pipeline system that connects our Orla Plant, as well as third-party plants to the Waha Oasis Header.
Energy Transfer operates one of the largest intrastate pipeline systems in the United States providing energy logistics to major trading hubs and industrial consumption areas throughout the United States. Our intrastate transportation and storage segment focuses on the transportation of natural gas to major markets from various prolific natural gas producing areas (Permian, Barnett, Haynesville and Eagle Ford Shale) through our Oasis pipeline, our ETC Katy pipeline, our natural gas pipeline and storage systems that are referred to as the ET Fuel System, and our HPL System, as further described below.
Our intrastate transportation and storage segment’s 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 a fee 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.
We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and marketing companies on our HPL System. Generally, we purchase natural gas from either the market (including purchases from our marketing operations) or from producers at the wellhead. To the extent the natural gas comes from producers, it is primarily purchased at a discount to a specified market price and typically resold to customers based on an index price. In addition, our intrastate transportation and storage segment generates revenues from fees charged for storing customers’ working natural gas in our storage facilities and from managing natural gas for our own account.

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Interstate Transportation and Storage Segment
Natural gas transportation pipelines receive natural gas from supply sources including other transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users and other pipelines. Through our interstate transportation and storage segment, we directly own and operate approximately 12,500 miles of interstate natural gas pipelines with approximately 10.7 Bcf/d of transportation capacity and another approximately 6,770 miles and 10.6 Bcf/d of transportation capacity through joint venture interests.
ETO’s vast interstate natural gas network spans the United States from Florida to California and Texas to Michigan, offering a comprehensive array of pipeline and storage services. Our pipelines have the capability to transport natural gas from nearly all Lower 48 onshore and offshore supply basins to customers in the Southeast, Gulf Coast, Southwest, Midwest, Northeast and Canada. Through numerous interconnections with other pipelines, our interstate systems can access virtually any supply or market in the country. As discussed further herein, our interstate segment operations are regulated by the FERC, which has broad regulatory authority over the business and operations of interstate natural gas pipelines.
Lake Charles LNG, our wholly-owned subsidiary, owns an 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 storage capacity and the regasification facility has a send out capacity of 1.8 Bcf/d. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly-owned subsidiary of Shell.
LCL, our wholly-owned subsidiary, is currently developing a natural gas liquefaction facility 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. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles site. In December 2019, ET announced a comprehensive commercial tender package has been issued to engineering, procurement and construction contractors to submit final bids for the proposed Lake Charles LNG liquefaction project being developed with Shell US LNG, LLC. The project would modify ETO’s existing LNG import facility to add LNG liquefaction capacity of 16.45 million tonnes per annum for expert to global markets. The commercial bids are expected to be received in the second quarter of 2020.
The results from our interstate transportation and storage segment are primarily derived from the fees we earn from natural gas transportation and storage services.
Midstream Segment
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 and the proximity of storage facilities to production areas and end-use markets. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems, that collect natural gas from points near producing wells and transports it to larger pipelines for further transportation.
Treating plants remove carbon dioxide and hydrogen sulfide from natural gas that is higher in carbon dioxide, hydrogen sulfide or certain other contaminants, to ensure that it meets pipeline quality specifications. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream. 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 can be processed to take advantage of favorable margins for NGLs extracted from the gas stream.
Through our midstream segment, we own and operate natural gas gathering and NGL pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing capacity of approximately 8.8 Bcf/d. Our midstream segment focuses on the gathering, compression, treating, blending, and processing, and our operations are currently concentrated in major producing basins and shales in South Texas, West Texas, New Mexico, North Texas, East Texas, West Virginia, Pennsylvania, Ohio, Oklahoma, Kansas and Louisiana. Many of our midstream assets are integrated with our intrastate transportation and storage assets.
Our midstream segment also includes a 60% interest in Edwards Lime Gathering, LLC, which operates natural gas gathering, oil pipeline and oil stabilization facilities in South Texas and a 75% membership interest in ORS, which operates a natural gas gathering system in the Utica shale in Ohio.
Our midstream segment results are derived primarily from margins we earn for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems and the natural gas and NGL volumes processed at our processing and treating facilities.

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NGL and Refined Products Transportation and Services Segment
Our 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.
Our NGL and refined products transportation and services segment includes:
approximately 4,515 miles of NGL pipelines;
NGL and propane fractionation facilities with an aggregate capacity of 825 MBbls/d;
NGL storage facility in Mont Belvieu with a working storage capacity of approximately 50 MMBbls; and
other NGL storage assets, located at our Cedar Bayou and Hattiesburg storage facilities, and our Nederland, Marcus Hook and Inkster NGL terminals with an aggregate storage capacity of approximately 13 MMBbls.
We are currently constructing a seventh fractionator, which went into operation in the first quarter of 2020, and an eighth fractionator, which we expect to be operational in the second quarter of 2021, at our Mont Belvieu facility. In addition, we are constructing an expansion to the Lone Star Express pipeline, which is expected to be in service early in the fourth quarter of 2020. The NGL pipelines primarily transport NGLs from the Permian and Delaware basins and the Barnett and Eagle Ford Shales to Mont Belvieu.
NGL terminalling services are facilitated by approximately 8 MMBbls of NGL storage capacity. These operations also support our liquids blending activities, including the use of our patented butane blending technology. Refined products operations provide transportation and terminalling services through the use of approximately 3,265 miles of refined products pipelines and approximately 35 active refined products marketing terminals. Our marketing terminals are located primarily in the northeast, midwest and southwest United States, with approximately 8 MMBbls of refined products storage capacity. Our refined products operations utilize our integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions throughout the United States. The mix of products delivered through our refined products pipelines varies seasonally, with gasoline demand peaking during the summer months, and demand for heating oil and other distillate fuels peaking in the winter. 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.
Revenues in this segment are 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. Fees are market-based, negotiated with customers and competitive with regional regulated pipelines and fractionators. Storage revenues are derived from base storage and throughput fees. This segment also derives revenues from the marketing of NGLs and processing and fractionating refinery off-gas.
Crude Oil Transportation and Services Segment
Our crude oil operations provide transportation (via pipeline and trucking), terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest, northwestern and northeastern United States. Through our crude oil transportation and services segment, we own and operate (through wholly-owned subsidiaries or joint venture interests) approximately 10,770 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States. This segment includes equity ownership interests in four crude oil pipelines, the Bakken Pipeline system, Bayou Bridge Pipeline, White Cliffs Pipeline and Maurepas Pipeline. Our crude oil terminalling services operate with an aggregate storage capacity of approximately 64 MMBbls, including approximately 29 MMBbls at our Gulf Coast terminal in Nederland, Texas, approximately 18.2 MMBbls at our Gulf coast terminal on the Houston Ship Channel, approximately 7.6 MMBbls at our Cushing facility in Cushing, Oklahoma and approximately 3.2 MMBbls at our Fort Mifflin terminal complex in Pennsylvania. Our crude oil acquisition and marketing activities utilize our pipeline and terminal assets, our proprietary fleet crude oil tractor trailers and truck unloading facilities, as well as third-party assets, to service crude oil markets principally in the midcontinent United States.
Revenues throughout our crude oil pipeline systems are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed with the FERC and other state regulatory agencies, as applicable.
Our crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil. 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;

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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.
Investment in Sunoco LP
Sunoco LP is engaged in the distribution of motor fuels to independent dealers, distributors, and other commercial customers and the distribution of motor fuels to end-user customers at retail sites operated by commission agents. Additionally, it receives rental income through the leasing or subleasing of real estate used in the retail distribution of motor fuel. Sunoco LP also operates 75 retail stores located in Hawaii and New Jersey.
Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent operators of commission agent locations and other commercial 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 Sunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,474 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LP believes it is one of the largest independent motor fuel distributors of Chevron, Exxon 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 operations primarily consist of fuel distribution and marketing.
Investment in USAC
USAC provides natural gas compression services throughout the United States, including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales. USAC provides compression services to its customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes. As such, USAC’s compression services play a critical role in the production, processing and transportation of both natural gas and crude oil.
USAC operates a modern fleet of compression units, with an average age of approximately six years. USAC’s standard new-build compression units are generally configured for multiple compression stages allowing USAC to operate its units across a broad range of operating conditions. As part of USAC’s services, it engineers, designs, operates, services and repairs its compression units and maintains related support inventory and equipment.
USAC provides compression services to its customers under fixed-fee contracts with initial contract terms typically between six months and five years, depending on the application and location of the compression unit. USAC typically continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into take-or-pay contracts whereby its customers are required to pay a monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of its cash flows. USAC is not directly exposed to commodity price risk because it does not take title to the natural gas or crude oil involved in its services and because the natural gas used as fuel by its compression units is supplied by its customers without cost to USAC.
USAC’s assets and operations are all located and conducted in the United States.
As of December 31, 2019, USAC had 3,682,968 horsepower in its fleet and 56,500 large horsepower on order for expected delivery during 2020.

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All Other Segment
Our “All Other” segment includes the following:
Our approximately 7.4% non-operating interest in PES, which owns a refinery in Philadelphia.
Our marketing operations in which we market the natural gas that flows through our gathering and intrastate transportation 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 suppliers 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 of natural gas, less the costs of transportation. For the off-system gas, we purchase gas or act as an agent for small independent producers that may not have marketing operations.
Our natural gas compression equipment business which has operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma, Pennsylvania and Texas.
Our wholly-owned subsidiary, Dual Drive Technologies, Ltd. (“DDT”), which provides compression services to customers engaged in the transportation of natural gas, including our other segments.
Our subsidiaries are involved in the management of coal and natural resources properties and the related collection of royalties. We also earn 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.
PEI Power LLC and PEI Power II, which own and operate a facility in Pennsylvania that generates a total of 75 megawatts of electrical power.
Our 51% ownership interest in SemCAMS, which owns and operates natural gas processing and gathering facilities in Alberta, Canada.
Asset Overview
The descriptions below include summaries of significant assets within the Partnership’s reportable segments. 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.
Intrastate Transportation and Storage
The following details our pipelines and storage facilities in the intrastate transportation and storage segment:
Description of Assets Ownership Interest Miles of Natural Gas Pipeline Pipeline Throughput Capacity
(Bcf/d)
 Working Storage Capacity
(Bcf/d)
ET Fuel System 100% 3,150
 5.2
 11.2
Oasis Pipeline (1)
 100% 750
 2.0
 
HPL System 100% 3,920
 5.3
 52.5
ETC Katy Pipeline 100% 460
 2.9
 
Regency Intrastate Gas 100% 450
 2.1
 
Comanche Trail Pipeline 16% 195
 1.1
 
Trans-Pecos Pipeline 16% 143
 1.4
 
Old Ocean Pipeline, LLC 50% 240
 0.2
 
Red Bluff Express Pipeline 70% 108
 1.4
 
(1) 
Includes bi-directional capabilities
The following information describes our 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

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strategically located near high-growth production areas and provides access to the Waha Hub near Pecos, Texas, the Maypearl Hub in Central Texas and the Carthage Hub in East Texas, the three major natural gas trading centers in Texas.
The ET Fuel System also includes our 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 our 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 our Godley processing plant which gives us 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 1.3 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 our gathering system known as the Southeast Texas System and is an important component to maximizing our Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by (i) providing access for natural gas gathered on the Southeast Texas System to other third-party supply and market points and interconnecting pipelines and (ii) allowing us to bypass our 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, Beaumont 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 us 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, Carthage and Agua Dulce, as well as our 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, 2019, we had approximately 19.0 Bcf committed under fee-based arrangements with third parties and approximately 27.3 Bcf stored in the facility for our own account.
The ETC Katy Pipeline connects three treating facilities, one of which we own, with our gathering system known as Southeast Texas System. The ETC Katy pipeline serves producers in East and North Central Texas and provided access to the Katy Hub. The ETC Katy pipeline expansions include the 36-inch East Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy expansion connecting Grimes to the Katy Hub, and the 42-inch Southeast Bossier pipeline connecting our 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.
Comanche Trail is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, 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 Pecos, Texas to the United States/Mexico border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos.
Old Ocean is a 240-mile intrastate pipeline system that delivers natural gas from Ellis County, Texas to Brazoria County, Texas. The Partnership owns a 50% membership interest in and operates Old Ocean.
The Red Bluff Express Pipeline is an approximately 108-mile intrastate pipeline that runs through the heart of the Delaware basin and connects our Orla Plant, as well as third-party plants to the Waha Oasis Header. The Partnership owns a 70% membership interest in and operates Red Bluff Express.

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Interstate Transportation and Storage
The following details our pipelines in the interstate transportation and storage segment:
Description of Assets Ownership Interest Miles of Natural Gas Pipeline 
Pipeline Throughput Capacity
(Bcf/d)
 
Working Gas Capacity
(Bcf/d)
Florida Gas Transmission 50% 5,362
 3.5
 
Transwestern Pipeline 100% 2,614
 2.1
 
Panhandle Eastern Pipe Line (1)
 100% 6,402
 2.8
 73.4
Trunkline Gas Company 100% 2,231
 0.9
 13.0
Tiger Pipeline 100% 197
 2.4
 
Fayetteville Express Pipeline 50% 185
 2.0
 
Sea Robin Pipeline 100% 785
 2.0
 
Stingray Pipeline 100% 302
 0.40
 
Rover Pipeline 32.6% 713
 3.25
 
Midcontinent Express Pipeline 50% 512
 1.8
 
Gulf States 100% 10
 0.1
 
(1) 
Natural gas storage assets are owned by Southwest Gas.
The following information describes our principal interstate transportation and storage assets:
Florida Gas Transmission Pipeline (“FGT”) has mainline capacity of 3.5 Bcf/d and approximately 5,362 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 approximately 60% of the natural gas consumed in the state. In addition, FGT’s system operates and maintains multiple 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, industrial end-users and local distribution companies. FGT is owned by Citrus, a 50/50 joint venture with KMI.
Transwestern Pipeline transports natural gas supply from 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. The system has bi-directional capabilities and can access Texas and Midcontinent natural gas market hubs, as well as major western markets in Arizona, Nevada and California.  Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
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. Panhandle contracts for over 73 Bcf of natural gas storage.
Trunkline Gas Company’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. Trunkline has one natural gas storage field located in Louisiana.
Tiger Pipeline is a bi-directional system that extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, interconnecting with multiple interstate pipelines.
Fayetteville Express Pipeline originates near Conway County, Arkansas and continues eastward to Panola County, Mississippi with multiple pipeline interconnections along the route.  Fayetteville Express Pipeline is owned by a 50/50 joint venture with KMI.
Sea Robin Pipeline’s system consists of two offshore Louisiana natural gas supply pipelines extending 120 miles into the Gulf of Mexico.
Stingray Pipeline is an interstate natural gas pipeline system with related assets located in the western Gulf of Mexico and Johnson Bayou, Louisiana.

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Rover Pipeline is a large diameter pipeline with total capacity to transport 3.25 Bcf/d natural gas from processing plants in West Virginia, Eastern Ohio and Western Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the gas is delivered for distribution to markets across the United States, as well as to Ontario, Canada.
Midcontinent Express Pipeline originates near Bennington, Oklahoma and traverses 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, the operator of the system.
Gulf States Transmission is a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.
Regasification Facility
Lake Charles LNG, our wholly-owned subsidiary, 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/d.
Liquefaction Project
LCL, our wholly-owned subsidiary, is in the process of developing an LNG liquefaction project at the site of our Lake Charles LNG import terminal and regasification facility. The liquefaction facility 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 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. On June 18, 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. LCL and Shell are actively involved in a variety of activities related to the development of the project. LCL has also been marketing LNG offtake to numerous potential customers in Asia and Europe.
In December 2019, ET announced a comprehensive commercial tender package which was issued to engineering, procurement and construction contractors to submit final bids for the proposed Lake Charles LNG liquefaction project being developed with Shell US LNG, LLC. The commercial bids are expected to be received in the second quarter of 2020.
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, LCL 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.
Midstream
The following details our assets in the midstream segment:
Description of Assets 
Net Gas Processing Capacity
(MMcf/d)
South Texas Region:  
Southeast Texas System 410
Eagle Ford System 1,920
Ark-La-Tex Region 1,442
North Central Texas Region 700
Permian Region 2,740
Midcontinent Region 1,385
Eastern Region 200

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The following information describes our 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 ETC Katy Pipeline and is also connected to the Oasis Pipeline. The Southeast Texas System includes two natural gas processing plants (La Grange and Alamo) with aggregate capacity of 410 MMcf/d. The La Grange and Alamo processing plants are natural gas processing plants that process the rich gas that flows through our gathering system to produce residue gas and NGLs. Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines to Lone Star.
Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our 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 our 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 1.92 Bcf/d. Our Chisholm, Kenedy, Jackson and King Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our NGL pipelines for delivery of NGLs to Lone Star.
Ark-La-Tex Region:
Our Northern Louisiana assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with several pipelines, including our Tiger Pipeline. Our Northern Louisiana assets include the Bistineau, Creedence, and Tristate Systems, which collectively include three natural gas treating facilities, with aggregate capacity of 1.4 Bcf/d.
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, a residue gas pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that provides connections to the Mont Belvieu market for NGLs produced from our processing plants. Collectively, the ten natural gas processing facilities (Dubach, Dubberly, Lisbon, Salem, Elm Grove, Minden, Ada, Brookeland, Lincoln Parish and Mt. Olive) have an aggregate capacity of 1.3 Bcf/d.
Through the gathering and processing systems described above and their interconnections with RIGS in north Louisiana, as well as other pipelines, we offer 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. Our North Central Texas assets include our Godley and Crescent plants, which process rich gas produced from the Barnett Shale and STACK play, with aggregate capacity of 700 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 our system to the Waha Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the midcontinent 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 eleven processing facilities (Waha, Coyanosa, Red Bluff, Halley, Jal, Keyston, Tippet, Orla, Panther, Rebel and Arrowhead) with an aggregate processing capacity of 2.4 Bcf/d and one natural gas conditioning facility with aggregate capacity of 200 MMcf/d.
We own a 50% membership interest in Mi Vida JV, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West Texas. We operate the plant and related facilities on behalf of Mi Vida JV.

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We own a 50% 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.
Midcontinent Region:
The Midcontinent 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 and the STACK in central Oklahoma. These mature basins have continued to provide generally long-lived, predictable production volume. Our Midcontinent assets are extensive systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include sixteen natural gas processing facilities (Mocane, Beaver, Antelope Hills, Woodall, Wheeler, Sunray, Hemphill, Phoenix, Hamlin, Spearman, Red Deer, Lefors, Cargray, Gray, Rose Valley, and Hopeton) with an aggregate capacity of approximately 1.4 Bcf/d.
We operate our Midcontinent 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.
We also own 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 eleven counties in Pennsylvania, four counties in Ohio, three counties in West Virginia, and gather natural gas from the Marcellus and Utica basins. Our Eastern Region assets include approximately 600 miles of natural gas gathering pipeline, natural gas trunklines, fresh-water pipelines, and nine gathering and processing systems, as well as the 200 MMcf/d Revolution processing plant, which feeds into our Mariner East and Rover pipeline systems.
We also own a 51% membership interest in Aqua – ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania.
We own a 75% membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13 miles of 30-inch and 3 miles of 24-inch gathering trunklines, that delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern Transmission, Leach Xpress, Rover and DEO TPL-18.

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NGL and Refined Products Transportation and Services
The following details the assets in our NGL and refined products transportation and services segment:
Description of Assets 
Miles of Liquids Pipeline (2)
 
NGL Fractionation / Processing Capacity
(MBbls/d)
 
Working Storage Capacity
(MBbls)
Liquids Pipelines:      
Lone Star Express 535
 
 
West Texas Gateway Pipeline 512
 
 
Lone Star 1,617
 
 
Mariner East 670
 
 
Mariner South 97
 
 
Mariner West 395
 
 
White Cliffs Pipeline(3)
 527
 
 
Other NGL Pipelines 162
 
 
Liquids Fractionation and Services Facilities:      
Mont Belvieu Facilities 182
 790
 50,000
Sea Robin Processing Plant(1)
 
 26
 
Refinery Services(1)
 103
 35
 
Hattiesburg Storage Facilities 
 
 3,000
Cedar Bayou 
 
 1,600
NGL Terminals:      
Nederland 
 
 1,200
Marcus Hook Industrial Complex 
 132
 6,000
Inkster 
 
 860
Refined Products Pipelines: 
 
 
    Eastern region pipelines 957
 
 
    Midcontinent region pipelines 349
 
 
    Southwest region pipelines 876
 
 
    Inland Pipeline 581
 
 
    JC Nolan Pipeline 502
 
 
Refined Products Terminals:      
Eagle Point 
 
 7,000
Marcus Hook Industrial Complex 
 
 1,000
Marcus Hook Tank Farm 
 
 2,000
Marketing Terminals 
 
 8,000
JC Nolan Terminal 
 
 134
(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.
(3) 
The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
The following information describes our 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, with throughput capacity of approximately 500 MBbls/d, that delivers mixed NGLs from processing plants in the

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Permian Basin, the Barnett Shale, and from East Texas to the Mont Belvieu NGL storage facility. An expansion of the pipeline is currently underway, which will add approximately 400 MBbls/d of NGL pipeline capacity from Lone Star’s pipeline system near Wink, Texas to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas. It is expected to be in service by the fourth quarter of 2020.
The West Texas Gateway Pipeline transports NGLs produced in the Permian and Delaware Basins and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput capacity of approximately 240 MBbls/d.
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 our 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, began service in December 2018. The Mariner East pipeline has a throughput capacity of approximately 345 MBbls/d.
The Mariner South liquids pipeline delivers export-grade propane and butane products from Lone Star’s Mont Belvieu, Texas storage and fractionation complex to our marine terminal in Nederland, Texas and has a throughput capacity of approximately 200 MBbls/d.
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 and has a throughput capacity of approximately 50 MBbls/d.
The White Cliffs NGL pipeline, which we have 51% ownership interest in and which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, transports NGLs produced in the DJ Basin to Cushing, where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 40 MBbls/d.
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.
Our Mont Belvieu storage facility is an integrated liquids storage facility with approximately 50 MMBbls of salt dome capacity providing 100% fee-based cash flows. The Mont Belvieu storage facility has access to multiple NGL and refined products pipelines, the Houston Ship Channel trading hub, and numerous chemical plants, refineries and fractionators.
Our Mont Belvieu fractionators handle NGLs delivered from several sources, including the Lone Star Express pipeline and the Justice pipeline. Fractionator VI was placed in service in February 2019, Fractionator VII was placed in service in the first quarter of 2020, and Fractionator VIII is currently under construction and is scheduled to be operational by the second quarter of 2021.
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 MMBbls of salt dome capacity, providing 100% fee-based cash flows.
The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from fixed fee storage contracts, throughput fees, and revenue from blending butane into refined gasoline.
The Nederland terminal, in addition to crude oil activities, also provides approximately 1.2 MMBbls 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 MMbbls of NGL storage capacity in underground caverns, 4 MMbbls of above-ground refrigerated storage, and related commercial agreements. The terminal has a total active refined products storage capacity of approximately 1 MMbbls. The facility can receive NGLs and refined products via marine vessel, pipeline, truck and rail, and can deliver via marine vessel,

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pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates and third-party customers, the Marcus Hook Industrial Complex currently serves as an off-take outlet for our Mariner East 1 pipeline system.
The Inkster terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls of NGLs. We use 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.
The Eastern region refined products pipelines consist of approximately 615 miles of 6-inch to 16-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 180 miles of various diameters refined products pipeline in New Jersey (including 80 miles of the 16-inch diameter Harbor Pipeline).
The midcontinent region refined products pipelines primarily consist of approximately 296 miles of 3-inch to 12-inch refined products pipelines in Ohio and approximately 53 miles of 6-inch and 8-inch refined products pipeline in Michigan.
The Southwest region refined products pipelines are located in Eastern Texas and consist primarily of approximately 876 miles of 8-inch diameter refined products pipeline.
The Inland refined products pipeline is approximately 580 miles of pipeline in Ohio, consisting of 72 miles of 12-inch diameter refined products pipeline in Northwest Ohio, 206 miles of 10-inch diameter refined products pipeline in vicinity of Columbus, Ohio, 135 miles of 8-inch diameter refined products pipeline in western Ohio, and 168 miles of 6-inch diameter refined products pipeline in Northeast Ohio.
The JC Nolan Pipeline is a joint venture between a wholly-owned subsidiary of the Partnership and a wholly-owned subsidiary of Sunoco LP, which transports diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and was placed into service in July 2019 and has a throughput capacity of approximately 36 MBbls/d.
We have approximately 35 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls 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 7 MMBbls, 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 MMBbls of refined products storage. The terminal receives and delivers refined products via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.
The JC Nolan Terminal, located in Midland, Texas, is a joint venture between a wholly-owned entity of the Partnership and wholly-owned entity of Sunoco LP, which provides diesel fuel storage that was placed into service in August 2019.
This segment also includes the following joint ventures: 15% membership interest in the Explorer Pipeline Company, a 1,850-mile pipeline which originates from refining centers in Beaumont, Port Arthur, and Houston, Texas and extends to Chicago, Illinois; 31% membership interest in the Wolverine Pipe Line Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; 17% membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings, Montana and extends to Moses Lake, Washington.

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Crude Oil Transportation and Services
The following details our pipelines and terminals in its crude oil transportation and services operations:
Description of Assets Ownership Interest 
Miles of Crude Pipeline (1)
 Working Storage Capacity
(MBbls)
Dakota Access Pipeline 36.40% 1,172
 
Energy Transfer Crude Oil Pipeline 36.40% 744
 
Bayou Bridge Pipeline 60% 212
 
Permian Express Pipelines 87.7% 1,712
 
Wattenberg Oil Trunkline 100% 75
 360
White Cliffs Pipeline(2)
 51% 527
 100
Maurepas Pipeline 51% 106
 
Other Crude Oil Pipelines 100% 6,222
 
Nederland Terminal 100% 
 29,000
Fort Mifflin Terminal 100% 
 3,175
Eagle Point Terminal 100% 
 1,300
Midland Terminal 100% 
 2,000
Marcus Hook Industrial Complex 100% 
 1,000
Houston Terminal 100% 
 18,200
Cushing Facility 100% 
 7,600
Patoka, Illinois Terminal 87.7% 
 2,000
(1) 
Miles of pipeline as reported to PHMSA.
(2) 
The White Cliffs Pipeline consists of two parallel, 12-inch common carrier crude oil pipelines: one crude oil pipeline and one NGL pipeline.
Our crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of crude oil from producers to end-user markets. The following details our assets in the crude oil transportation and services segment:
Crude Oil Pipelines
Our crude oil pipelines consist of approximately 10,770 miles of crude oil trunk and gathering pipelines in the southwest, northwest and midwest United States, including our wholly-owned interests in West Texas Gulf, Permian Express Terminal LLC, Mid-Valley and Wattenberg Oil Trunkline. Additionally, we have equity ownership interests in two crude oil pipelines. Our 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. Our 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 1,916 mile pipeline with capacity of 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 our 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 12, 20, 24 and 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.

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ETCO went into service on June 1, 2017 and consists of approximately 675 miles of mostly 30-inch converted natural gas pipeline and 69 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 ETO and Phillips 66, in which ETO 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 consists of 24-inch pipe from Lake Charles, Louisiana to St. James, Louisiana, which went into service in March 2019.
With the completion of Phase II, Bayou Bridge Pipeline has a capacity of 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 Express 3, Permian Express 4, which became operational in May 2019, Permian Longview and Louisiana Access pipelines, as well as the Longview to Louisiana and Nederland Access 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.
White Cliffs Pipeline. White Cliffs Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, owns a12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that transports crude oil from Platteville, Colorado to Cushing, Oklahoma.
Maurepas Pipeline. The Maurepas Pipeline, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries in the Gulf Coast region.
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 and Kansas. We have the ability to deliver substantially all of the crude oil gathered on our Oklahoma and Kansas systems to Cushing. We are one of the largest purchasers of crude oil from producers in the area, 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, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has a total storage capacity of approximately 29 MMBbls 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 MMBbls/d of crude oil. In addition to our 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 MMBbls.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has three 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 MMBbls/d of crude oil to our 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.

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The Fort Mifflin terminal contains two ship docks with freshwater drafts and a total storage capacity of approximately 575 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. This facility has a total storage capacity of approximately 2.6 MMBbls. Darby Creek receives crude oil from the Fort Mifflin terminal and Hog Island wharf via our pipelines. The tank farm then stores the crude oil and transports it to the PES refinery via our 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 1.3 MMBbls 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 MMBbls of crude oil storage, a combined 20 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 MMBbls.
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 MMBbls of crude oil storage.
Houston Terminal. The Houston Terminal, which was acquired by ET in the SemGroup acquisition and contributed to ETO in February 2020, consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2 MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels and seven barge docks which can accommodate 23 barges simultaneously, three crude oil pipelines connecting to four refineries and numerous rail and truck loading spots.
Cushing Facilities. The Cushing Facility, which was acquired by ET in the SemGroup acquisition and contributed to ETO in January 2020, has approximately 7.6 MMBbls crude oil storage, of which 5.6 MMBbls are leased to customer and 2.0 MMBbls are available for crude oil operations, blending and marketing activities. The storage terminal has inbound connections with the White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas, and two-way connections with all of the other major storage terminals in Cushing. The Cushing terminal also includes truck unloading facilities.
Crude Oil Acquisition and Marketing
Our crude oil acquisition and marketing operations are conducted using our assets, which include approximately 575 crude oil transport trucks, 360 trailers and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets.
Investment in Sunoco LP
Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent operators of commission agent locations and other commercial 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 Sunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,474 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest, South Central and Southeast regions of the United States. Sunoco LP believes it is one of the largest independent motor fuel distributors of Chevron, Exxon and Valero branded motor fuel in the United States. In addition to distributing motor fuels, Sunoco LP also

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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 operations primarily consist of fuel distribution and marketing.
Sunoco LP’s Fuel Distribution and Marketing Operations
Sunoco LP’s fuel distribution and marketing operations are conducted by the following consolidated subsidiaries:
Sunoco, LLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in 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, Texas, Arkansas and New York;
Sunoco Retail LLC (“Sunoco Retail”), a Pennsylvania limited liability company, owns and operates retail stores that sell motor fuel and merchandise primarily in New Jersey;
Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands; and
Aloha Petroleum, Ltd. (“Aloha”), a Hawaii corporation, owns and operates retail stores on the Hawaiian Islands.
Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distributes 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:
75 company owned and operated retail stores;
537 independently operated consignment locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with such operators;
6,742 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
2,581 other commercial customers, including unbranded convenience stores, other fuel distributors, school districts and municipalities and other industrial customers.
Sunoco LP’s Other Operations
Sunoco LP’s other operations include retail operations in Hawaii and New Jersey, credit card services and franchise royalties.
Investment in USAC
The following details the assets of USAC:
USAC’s modern, standardized compression unit fleet is powered primarily by the Caterpillar, Inc.’s 3400, 3500 and 3600 engine classes, which range from 401 to 5,000 horsepower per unit. These larger horsepower units, which USAC defines as 400 horsepower per unit or greater, represented 86.2% of its total fleet horsepower (including compression units on order) as of December 31, 2019. In addition, a portion of its fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications.

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The following table provides a summary of USAC’s compression units by horsepower as of December 31, 2019:
Unit Horsepower Fleet Horsepower Number of Units 
Horsepower on Order (1)
 Number of Units on Order Total Horsepower Total Number of Units
Small horsepower            
<400 516,674
 3,031
 
 
 516,674
 3,031
             
Large horsepower            
>400 and <1,000 426,384
 730
 9,000
 15
 435,384
 745
>1,000 2,739,910
 1,690
 47,500
 19
 2,787,410
 1,709
Total large horsepower 3,166,294
 2,420
 56,500
 34
 3,222,794
 2,454
Total horsepower 3,682,968
 5,451
 56,500
 34
 3,739,468
 5,485
(1) 
As of December 31, 2019, USAC had 56,500 large horsepower compression units on order for delivery during 2020.
All Other
The following details the significant assets in the “All Other” segment.
Contract Services Operations
We own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and Btu management. Our contract treating services are primarily located in Texas, Louisiana and Arkansas.
Compression
We own DDT, which provides compression services to customers engaged in the transportation of natural gas, including our subsidiaries in other segments.
Natural Resources Operations
Our Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. We also earn 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, 2019, we owned or controlled approximately 762 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.
Canadian Operations
Our Canadian operations, which were acquired in the SemGroup acquisition, include a 51% ownership interest in SemCAMS, which owns and operates natural gas processing and gathering facilities in Alberta, Canada. The Canadian operations assets include four sour natural gas processing plants and two sweet natural gas processing plants that have a combined operating capacity of 1,290 MMcf/d and a network of approximately 848 miles of natural gas gathering and transportation pipelines. The principal process performed at the processing plants is to remove contaminants and render the gas saleable to downstream pipelines and markets.
Business Strategy
We believe we have engaged, and will continue to engage, in a well-balanced plan for growth through strategic acquisitions, internally generated expansion, measures aimed at increasing the profitability of our existing assets and executing cost control measures where appropriate to manage our operations.
We intend to continue to operate as a diversified, growth-oriented limited partnership. We believe that by pursuing independent operating and growth strategies we will be best positioned to achieve our objectives. We balance our desire for growth with our goal of preserving a strong balance sheet, ample liquidity and investment grade credit metrics.

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Following is a summary of the business strategies of our core businesses:
Growth through acquisitions.  We intend to continue to make strategic acquisitions that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of our existing assets while supporting our investment grade credit ratings.
Engage in construction and expansion opportunities.  We intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream and transportation services.
Increase cash flow from fee-based businesses.  We intend to increase the percentage of our business conducted with third parties under fee-based arrangements in order to provide for stable, consistent cash flows over long contract periods while reducing exposure to changes in commodity prices.
Enhance profitability of existing assets.  We intend to increase the profitability of our existing asset base by adding new volumes under long-term producer commitments, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.
Competition
Natural Gas
The business of providing natural gas gathering, compression, treating, transportation, storage 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 segment 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 and gas companies, interstate and intrastate pipelines and other 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 and gas 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 Refined Products
In markets served by our crude oil and refined products pipelines, we face competition from other pipelines as well as rail and truck transportation. Generally, pipelines are the safest, 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.

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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 industrial end-users, 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.
Our 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, 2019, 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 of 1938 (“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, Rover, 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;

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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 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 the 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 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 in excess of $1.1 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 of 1978 (“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

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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 are subject to state statutes and regulations which could impose additional environmental, safety and operational requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL transportation systems. In some jurisdictions, state public utility commission oversight may include the possibility of fines, penalties and delays in construction related to these regulations. In addition, the rates, terms and conditions of service for shipments of NGLs on our pipelines are subject to regulation by the 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

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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, the 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 the 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 the 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 the FERC regarding our cost of service, may also be subject to review in the courts. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued an opinion in United Airlines, Inc., et al. v. FERC, finding that the FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a master limited partnership, or MLP, to include an income tax allowance in the cost of service underlying its rates, in addition to the discounted cash flow return on equity, would not result in the pipeline partnership owners double recovering their income taxes. The court vacated the FERC’s order and remanded to the FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. In December 2016, the FERC issued a Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Costs. The 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 in April 2017.
In March 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes in which the FERC found that an impermissible double recovery results from granting an MLP pipeline both an income tax allowance and a return on equity pursuant to the FERC’s discounted cash flow methodology. The FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. The FERC stated it will address the application of the United Airlines decision to non-MLP partnership forms as those issues arise in subsequent proceedings. Further, the FERC stated that it will incorporate the effects of the post-United Airlines policy changes and the Tax Cuts and Jobs Act of 2017 on industry-wide crude oil pipeline costs in the 2020 five-year review of the crude oil pipeline index level. The FERC will also apply the revised Policy Statement and the Tax Cuts and Jobs Act of 2017 to initial crude oil pipeline cost-of-service rates and cost-of-service rate changes on a going-forward basis under the FERC’s existing ratemaking policies, including cost-of-service rate proceedings resulting from shipper-initiated complaints. In July 2018, the FERC dismissed requests for rehearing and clarification of the March 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income tax costs.

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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. With the lower tax rate, and as discussed immediately above, the maximum tariff rates allowed by the FERC under its rate base methodology for master limited partnerships may be impacted by a lower income tax allowance component. Many of our interstate pipelines, such as Tiger, MEP and FEP, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and PEPL, have a mix of tariff rate, discount rate, and negotiated rate agreements. In addition, several of these pipelines are covered by approved settlements, where rate filings will be made in the future. As such, the timing and impact of these systems of any tax change is unknown at this time.
In March 2019, following the decision of the D.C. Circuit in Emera Maine v. Federal Energy Regulatory Commission, FERC issued a Notice of Inquiry regarding its policy for determining return on equity (“ROE”). FERC specifically sought information and stakeholder views to help FERC explore whether, and if so how, it should modify its policies concerning the determination of ROE to be used in designing jurisdictional rates charged by public utilities. FERC also expressly sought comment on whether any changes to its policies concerning public utility ROEs should be applied to interstate natural gas and oil pipelines. Initial comments were due in June 2019, and reply comments were due in July 2019. FERC has not taken any further action with respect to the Notice of Inquiry as of this time, and therefore we cannot predict what effect, if any, such development could have on our cost-of-service rates in the future.
The EPAct of 1992 required the FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, the 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. The 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, the 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 in March 2017. The FERC has taken no further action on the proposed rule to date.
Finally, in November 2017, the 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, the 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 the FERC clarify its November 2017 order or, in the alternative, grant rehearing of the November 2017 order.  The FERC extended the time frame to respond to such requests in January 2018, but has not yet taken final action. We are unable to predict how the FERC will respond to such requests.  Depending on how the 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 Pennsylvania Public Utility Commission 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 the 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

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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 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. In July 2019, PHMSA issued a final rule increasing those maximum civil penalties to $218,647 per day, with a maximum of $2,186,465 for a series of violations. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through 2019 and, among other things, require PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities, which was issued by PHMSA in January 2020. 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 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, 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. In October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the Mega Rule), the safety of hazardous liquid pipelines, and enhanced emergency order procedures. The gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming MAOP. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. This rule will take effect on July 1, 2020. PHMSA is then expected to issue the second

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part of the Mega Rule focusing on repair criteria in HCAs and creating new repair criteria for non-HCAs, requirements for inspecting pipelines following extreme events, updates to pipeline corrosion control requirements, and various other integrity management requirements. PHMSA is expected to subsequently issue the final part of the gas Mega Rule, the Gas Gathering Rule, focusing on requirements relating to gas gathering lines.
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. The safety and hazardous liquid pipelines rule discussed above, submitted to the Federal Register by PHMSA in October 2019, extended leak detection requirements to all non-gathering hazardous liquid pipelines and requires operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. This rule will also take effect on July 1, 2020. In addition, the enhanced emergency procedures rule also mentioned above focuses on increased emergency safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety. Unlike the other two rules submitted in October 2019, this rule took effect on December 2, 2019. 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 TRRC, 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

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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, the 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 was 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. In response to the decree, in April 2019, the EPA signed a determination that revision of the regulations is not necessary at this time. 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 refined 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, 2019 and 2018, accruals of $320 million and $337 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 ETC Sunoco’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $252 million and $263 million at December 31, 2019 and 2018, 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 ETC Sunoco, closed and/or sold refineries and other formerly

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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, 2019, the captive insurance company held $205 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. The Partnership’s consolidated balance sheet reflected $320 million in environmental accruals as of December 31, 2019.
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 $4 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

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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.” In April 2018 and July 2018, the EPA issued area designations for all areas not addressed in the November 2017 rule. States with moderate or high nonattainment areas must submit state implementation plans to the EPA by October 2021. 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 June 2015, the EPA and the United States Army Corps of Engineers (“USACE”) 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 USACE 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. In January 2018, the United States Supreme Court issued a decision finding that jurisdiction resides with the federal district courts. Also in January 2018, the EPA and USACE finalized a rule that would delay applicability of the rule to two years from the rule’s publication in the Federal Register. The EPA and USACE formally proposed a rule revising the definition of “waters of the United States” in December 2018. The proposed definition would substantially reduce the scope of waters that fall within the Clean Water Act’s jurisdiction, in part by excluding ephemeral streams. The EPA and USACE had previously determined that ephemeral streams could potentially qualify as “waters of the United States,” which would not be possible under the proposed definition. In January 2020, a new “waters of the United States” rule was finalized to replace the June 2015 rule. Under the final rule, the following four categories of waters would be defined as “waters of the United States”: traditional navigable waters and territorial seas; perennial and intermittent tributaries to those waters; lakes, ponds and impoundments of jurisdictional waters; and wetlands adjacent to jurisdictional waters. Additional litigation and administrative proceedings are expected in the future. As a result of these developments, future implementation of the June 2015 rule or any replacement 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

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impact on navigable waters in the event of a release of oil. 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 greenhouse gases (“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 (“VOC”) emissions. These Subpart OOOOa standards 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. In September 2018, the EPA proposed amendments to Subpart OOOOa that would reduce the 2016 standards’ fugitive emissions monitoring requirements and expand exceptions to controlling methane emissions from pneumatic pumps, among other changes. Various industry and environmental groups have separately challenged both the original 2016 standards and the EPA’s attempts to delay the implementation of the rule. In August 2019, the EPA proposed two options for further rescinding the Subpart OOOOa standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for volatile organic compounds, or VOCs, and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural gas category the natural gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the Subpart OOOOa standards applicable to all oil and natural gas sources, without removing any sources from that source category (and still requiring control of VOCs in general). 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 United States formally initiated the withdrawal process in November

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2019, 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, 2019, ET and its consolidated subsidiaries employed an aggregate of 12,812 employees, 1,551 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. 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. ETO, Panhandle, Sunoco LP and USAC 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 ETO’s, Panhandle’s, Sunoco LP’s and USAC’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.

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Risks Inherent in an Investment in Us
Cash distributions are not guaranteed and may fluctuate with our performance or other external factors.
Our principal source of earnings and cash flow is cash distributions from ETO. In addition, ETO’s earnings and cash flows are generated by its subsidiaries, including ETO’s investments in Sunoco LP and USAC. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETO and its subsidiaries, including Sunoco LP and USAC, make to their partners. ETO may not be able to continue to make quarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETO 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 ETO to us.
Our ability to distribute cash received from ETO 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 ETO and its subsidiaries, 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 in ETO, Sunoco LP and USAC, including the incentive distribution rights in Sunoco LP and, therefore, our cash flow is dependent upon the ability of ETO, Sunoco LP and USAC to make distributions in respect of those partnership interests.
We do not have any significant assets other than our partnership interests in ETO. As a result, our cash flow depends on the performance of ETO and its subsidiaries, including Sunoco LP and USAC, and their ability to make cash distributions, which is dependent on the results of operations, cash flows and financial condition of ETO and its subsidiaries, including Sunoco LP and USAC.
The amount of cash that ETO distributes to us each quarter depends upon the amount of cash ETO generates from its 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 ETO’s pipelines;
the level of throughput in processing and treating operations;
the fees charged and the margins realized by ETO, Sunoco LP and USAC 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 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.

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In addition, the actual amount of cash that ETO, and its subsidiaries, including Sunoco LP and USAC, 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.
ET does not have any control over many of these factors, including the level of cash reserves established by the board of directors. Accordingly, we cannot guarantee that ETO, Sunoco LP and USAC will have sufficient available cash to pay a specific level of cash distributions to their respective partners.
Furthermore, Unitholders should be aware that the amount of cash that our subsidiaries 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, our subsidiaries 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 ETO’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.
ETO may issue additional preferred equity, and Sunoco LP and USAC 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 ETO, Sunoco LP and USAC allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional preferred units, 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.

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The payment of distributions on any additional units issued by ETO, Sunoco LP and USAC 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 our 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, 2019, our directors and executive officers directly or indirectly own approximately 14% 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.
The control of our general partner may be transferred to a third party without Unitholder consent.
Our 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 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 ETO 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 ETO, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETO’s midstream business. Mr. Warren has been integral to the success of ETO’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 ETO to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETO’s ability to increase the cash distributions paid on its partnership interests.
ETO’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETO. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention

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from them that the management of our business requires. If ETO 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.
The consolidated debt level and debt agreements of ETO and its subsidiaries, including Sunoco LP and USAC, may limit the distributions we receive from ETO, as well as our future financial and operating flexibility.
ETO’s and its subsidiaries’ levels of indebtedness affect their operations in several ways, including, among other things:
a significant portion of ETO’s and its 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 ETO’s and its subsidiaries’ existing debt agreements require ETO and its subsidiaries, as applicable, to meet financial tests that may adversely affect their flexibility in planning for and reacting to changes in their respective businesses;
ETO’s and its 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;
ETO and its subsidiaries may be at a competitive disadvantage relative to similar companies that have less debt;
ETO and its subsidiaries may be more vulnerable to adverse economic and industry conditions as a result of their significant debt levels;
failure by ETO or its subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact ETO’s and/or its subsidiaries’ 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.

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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 may 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.
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 ETO, Sunoco LP and USAC, 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 ETO on acceptable terms, or at all.
ETO plans to fund its growth capital expenditures, including any new future pipeline construction projects and improvements or repairs to existing facilities that ETO may undertake, with proceeds from sales of ETO’s debt and equity securities and borrowings under its revolving credit facility; however, ETO cannot be certain that it will be able to issue debt and equity securities on terms satisfactory to it, or at all. In addition, ETO may be unable to obtain adequate funding under its current revolving credit facility because ETO’s lending counterparties may be unwilling or unable to meet their funding obligations. If ETO is unable to finance its expansion projects as expected, ETO could be required to seek alternative financing, the terms of which may not be attractive to ETO, or to revise or cancel its expansion plans.
A significant increase in ETO’s indebtedness that is proportionately greater than ETO’s issuance of equity could negatively impact ETO’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 ETO’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 $7.97 billion of our consolidated debt as of December 31, 2019 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.
Changes in LIBOR reporting practices or the method in which LIBOR is determined may adversely affect the market value of our current or future debt obligations, including our revolving credit facility.
As of December 31, 2019, we had outstanding approximately $7.97 billion of debt that bears interest at variable interest rates that use the LIBOR as a benchmark rate. On July 27, 2017, the Financial Conduct Authority (the “FCA”), which regulates LIBOR, announced that it intends to stop persuading or compelling banks to submit LIBOR quotations after 2021. It is unclear whether

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LIBOR will cease to exist or if new methods of calculating LIBOR will be established such that it continues to exist after 2021, or whether any alternative benchmark rate will attain market acceptance as a replacement for LIBOR. It is not possible to predict the further effect of the rules of the FCA, any changes in the methods by which LIBOR is determined or any other reforms to LIBOR that may be enacted in the United Kingdom, the European Union or elsewhere. Any such developments may cause LIBOR to perform differently than in the past, or cease to exist. In addition, any other legal or regulatory changes made by the FCA, the European Commission or any other successor governance or oversight body, or future changes adopted by such body, in the method by which LIBOR is determined or the change from LIBOR to an alternative benchmark rate may result in, among other things, a sudden or prolonged increase or decrease in LIBOR, a delay in the publication of LIBOR, and changes in the rules or methodologies in LIBOR, which may discourage market participants from continuing to administer or to participate in LIBOR’s determination, and, in certain situations, could result in LIBOR no longer being determined and published.
If a published U.S. dollar LIBOR rate is unavailable after 2021, the interest rates on our debt which are indexed to LIBOR will be determined using an alternative method, which may result in interest obligations which are more than or do not otherwise correlate over time with the payments that would have been made on such debt if U.S. dollar LIBOR was available in its current form or will be determined using an alternative benchmark rate as negotiated with our counterparties. Further, the same costs and risks that may lead to the discontinuation or unavailability of U.S. dollar LIBOR may make one or more of the alternative methods impossible or impracticable to determine. Alternative benchmark rate(s) may replace LIBOR and could affect our debt securities, derivative instruments, receivables, debt payments and receipts. At this time, it is not possible to predict the effect of any establishment of any alternative benchmark rate(s) and we cannot predict what alternative benchmark rate(s) will be negotiated with our counterparties. Any new benchmark rate will likely not replicate LIBOR exactly, and any changes to benchmark rates may have an uncertain impact on our cost of funds and our access to the capital markets. Any of these proposals or consequences could have a material adverse effect on our financing costs.
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.
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, 2019, we had approximately $124 million of debt on a stand-alone basis and approximately $51 billion of consolidated debt, excluding the debt of our unconsolidated 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

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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, 2019, the directors and executive officers of our general partner owned approximately 14% of our Common Units.
Litigation commenced by WMB against ET and its affiliates, if decided adverse to ET, could require ET to make a substantial payment to WMB.
WMB filed a complaint against ET and its affiliates in the Delaware Court of Chancery, alleging that the defendants breached the merger agreement between WMB, ET, and several of ET's affiliates. Following a ruling by the Court on June 24, 2016, which allowed for the subsequent termination of the merger agreement by ET 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 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, as well as new allegations that the ET Defendants breached an additional representation and warranty in the Merger Agreement. The ET 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 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 ET Defendants' amended counterclaims and to strike certain of the ET Defendants' affirmative defenses. On December 1, 2017, the Court issued a Memorandum Opinion granting Williams' motion to dismiss in part and denying it in part. On March 23, 2017, the Delaware Supreme Court affirmed the Court's June 24, 2016 ruling, and as a result, Williams conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending.
Trial is currently set for June 2020. Defendants cannot predict the outcome of the 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 William claims are without merit and intend to defend vigorously against them.
Risks Related to Conflicts of Interest
Although we control ETO and its subsidiaries, including Sunoco LP and USAC through our ownership of ETO’s general partner, ETO’s, Sunoco LP’s and USAC’s general partners owe fiduciary duties to ETO and ETO’s unitholders, Sunoco LP and Sunoco LP’s unitholders and USAC and USAC’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 ETO, Sunoco LP and USAC and their respective limited partners, on the other hand. The directors and officers of ETO’s, Sunoco LP’s and USAC’s general partners have fiduciary duties to manage ETO, Sunoco LP and USAC, respectively, in a manner beneficial to us. At the same time, the general partners have fiduciary duties to manage ETO, Sunoco LP and USAC in a manner beneficial to ETO, Sunoco LP and USAC and their respective limited partners. The boards of directors of ETO’s, Sunoco LP’s and USAC’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 ETO, Sunoco LP and USAC may arise in the following situations:
the allocation of shared overhead expenses to ETO, Sunoco LP, USAC and us;

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the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ETO, Sunoco LP and USAC, on the other hand;
the determination of the amount of cash to be distributed to ETO’s, Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future conduct of ETO’s, Sunoco LP’s and USAC’s businesses;
the determination whether to make borrowings under ETO’s, Sunoco LP’s and USAC’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 ETO, Sunoco LP and USAC is made available for ETO, Sunoco LP and USAC to pursue; and
any decision we make in the future to engage in business activities independent of ETO, Sunoco LP and USAC.
The fiduciary duties of our general partner’s officers and directors may conflict with those of ETO’s, Sunoco LP’s or USAC’s respective general partners.
Conflicts of interest may arise because of the relationships among ETO, Sunoco LP, USAC, 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 or officers are also directors and/or officers of ETO’s general partner, Sunoco LP’s general partner or USAC’s general partner, and have fiduciary duties to manage the respective businesses of ETO, Sunoco LP and USAC in a manner beneficial to ETO, Sunoco LP, USAC 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 ETO, and its subsidiaries, including Sunoco LP and USAC, 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;

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by a 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 favorable or advantageous 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’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 our 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 our 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.
We do not control, and therefore may not be able to cause or prevent certain actions by, certain of our joint ventures.
Certain of our operations are conducted through joint ventures, some of which have their own governing boards. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Consequently, it may be difficult or impossible for us to cause the joint venture entity to take actions that we believe would be in their or the joint venture’s best interests. Likewise, we may be unable to prevent actions of the joint venture. Differences in views among joint venture partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations.
ETO and its subsidiaries, including Sunoco LP and USAC, are exposed to the credit risk of their respective customers and derivative counterparties, and an increase in the nonpayment or 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 or nonperformance by ETO’s and its subsidiaries, including Sunoco LP’s and USAC’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. ETO and its subsidiaries 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 or nonperformance by ETO’s and its subsidiaries’

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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 ETO’s or its subsidiaries’ customers could have a material adverse effect on ETO’s or its subsidiaries’ respective results of operations and operating cash flows.
We compete with other businesses in our market with respect to attracting and retaining qualified employees.
Our continued success depends on our ability to attract and retain qualified personnel in all areas of our business. We compete with other businesses in our market with respect to attracting and retaining qualified employees. A tight labor market, increased overtime and a higher full-time employee ratio may cause labor costs to increase. A shortage of qualified employees may require us to enhance wage and benefits packages in order to compete effectively in the hiring and retention of such employees or to hire more expensive temporary employees. No assurance can be given that our labor costs will not increase, or that such increases can be recovered through increased prices charged to customers. We are especially vulnerable to labor shortages in oil and gas drilling areas when energy prices drive higher exploration and production activity.
The use of derivative financial instruments could result in material financial losses by ETO and its subsidiaries.
From time to time, ETO and its subsidiary Sunoco LP have sought to reduce their 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 ETO 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, ETO’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 ETO’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 ETO’s and its subsidiaries’ ability to operate and adversely affect their financial results.
ETO’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 ETO’s ability to pursue expansion projects. ETO 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. ETO’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 ETO 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, ETO 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 ETO’s business if it were to lose the right to use or occupy the property on which their pipelines are located. For example, following a 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

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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 ETO’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, ETO’s subsidiary, does not own all of the land on which its retail service stations are located. Sunoco LP has rental agreements for approximately 38.0% 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.
ETO and its subsidiaries may not be able to fully execute their growth strategies if they encounter increased competition for qualified assets.
ETO, and its subsidiaries, including Sunoco LP and USAC, 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. ETO and its subsidiaries regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that ETO and its subsidiaries believe will present opportunities to realize synergies and increase cash flow.
Consistent with their strategies, managements of ETO, Sunoco LP and USAC 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 ETO, Sunoco LP and USAC management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETO and its subsidiaries 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 ETO’s and its subsidiaries’ acquisition efforts will be successful or that any acquisition will be completed on favorable terms.
In addition, ETO its subsidiaries are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETO and its subsidiaries losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETO’s, Sunoco LP’s and USAC’s ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETO’s and its subsidiaries’ results of operations.
An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2019, our consolidated balance sheets reflected $5.17 billion of goodwill and $6.15 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 third quarter of 2019, the Partnership recognized a goodwill impairment of $12 million related to the Southwest Gas operations within the interstate segment primarily due to decreases in projected future revenues and cash flows. During the fourth quarter of 2019, the Partnership recognized a goodwill impairment of $9 million related to our North Central operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows.
During the fourth quarter of 2018, the Partnership recognized goodwill impairments of $378 million related to our Northeast operations within the midstream segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. These changes in assumptions reflect delays in the construction of third-party takeaway capacity in the Northeast. During 2019, Sunoco LP recognized a $30 million impairment charge on its contractual rights.

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During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments. The goodwill impairments consisted 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 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.
If ETO, and its subsidiaries, including Sunoco LP and USAC do not make acquisitions on economically acceptable terms, their future growth could be limited.
ETO and its subsidiaries’ 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.
ETO and its subsidiaries 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 ETO or its subsidiaries and may have greater financial resources and lower costs of capital.
Furthermore, even if ETO or its subsidiaries 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 ETO and its subsidiaries 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 ETO and its subsidiaries consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETO and its subsidiaries 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 ETO and its subsidiaries 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;

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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 or regulatory actions related to the Dakota Access Pipeline could cause an interruption to current or future operations, which could have an adverse effect on our business and results of operations.
On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia challenging permits issued by the United States Army Corps of Engineers (“USACE”) permitting Dakota Access, LLC (“Dakota Access”) to cross the Missouri River at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE allowing the pipeline to cross land owned by the USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened (collectively with SRST and CRST, the “Tribes”). Plaintiffs and Defendants filed cross motions for summary judgment which are pending before the court.
While we believe that the pending lawsuits are unlikely to adversely affect the continued operation or potential expansion 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 and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of current or 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 ETO’s midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products that are beyond our control.
The prices for natural gas, NGLs, crude oil and refined 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 oil production;
the level of natural gas, NGL, and 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 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.

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In the past, the prices of natural gas, NGLs and 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 oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGL and oil commodities could materially affect our profitability.
We are 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 ETO’s midstream operations, ETO 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.
ETO’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.
ETO’s crude oil and refined petroleum products pipelines face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude and 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.
We are subject to competition from other gathering, transportation, processing, storage and marketing operations that may be able to supply our customers with the same or comparable services at a lower price or otherwise on better terms. ETO competes with national, regional and local gathering, transportation and storage companies of widely varying sizes, financial resources and experience, including the major integrated oil companies. Its ability to compete could be harmed by numerous factors, including:
price competition;
the perception that another company can provide better service; and
the availability of alternative supply points, or supply points located closer to the operations of our customers.
Some of our competitors have greater financial, managerial and other resources than we do, and control substantially more storage or transportation capacity than we do. The competitors may expand their assets or operations, creating additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, transportation and storage systems or marketing operations in lieu of using our services. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers.
ETO 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, refined products, 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 ETO 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, refined products, natural gas and NGLs in the markets we serve and competition from other service providers.
A significant portion of ETO’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.

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ETO 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 ETO’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. ETO 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, ETO’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 ETO’s revenue is more dependent upon demand for storage from its customers.
The volume of crude oil and refined products transported through ETO’s crude oil and refined products 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 refined 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 refined products supplied from or delivered to any of these areas could materially reduce demand for crude oil or refined products in these areas. In either case, the volumes of crude oil or refined products transported in our crude oil and refined products pipelines and terminal facilities could decline.
The loss of existing customers by ETO’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.
ETO’s midstream facilities and transportation pipelines provide services related to natural gas wells that experience production declines over time, which ETO may not be able to replace with natural gas production from newly drilled wells in the same natural gas basins or in other new natural gas producing areas.
In order to maintain or increase throughput levels on ETO’s gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, ETO must continually contract for new natural gas supplies and natural gas transportation services.
A substantial portion of ETO’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. ETO’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. ETO 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 ETO’s systems connect. ETO 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, ETO has no control over producers or their production and contracting decisions.
While a substantial portion of ETO’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 ETO 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.

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The profitability of certain activities in ETO’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 ETO’s systems, natural gas is purchased from producers at the wellhead and then gathered and delivered to pipelines where it is typically resold various arrangements, including sales at index prices. Generally, the gross margins realized under these arrangements decrease in periods of low natural gas prices. ETO also enters into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which ETO agrees to gather and process natural gas received from producers.
Under percent-of-proceeds arrangements, ETO generally sells the residue gas and NGLs at market prices and remits 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, ETO delivers an agreed upon percentage of the residue gas and NGL volumes to the producer and sells the volumes kept to third parties at market prices. Under these arrangements, ETO’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 ETO’s revenues and results of operations.
Under keep-whole arrangements, ETO generally sells the NGLs produced from its 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, ETO 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 ETO processes the gas for a fee under processing fee agreements, it may guarantee recoveries to the producer. If recoveries are less than those guaranteed to the producer, ETO may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.
ETO 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 ETO 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, ETO receives revenue from its 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 ETO’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 off-gas processing and fractionation services and could have an adverse effect on our results of operations.
For ETO’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, 2019, 2018 and 2017, segment margin (a non-GAAP measure discussed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”) from ETO’s midstream operations totaled $2.45 billion, $2.38 billion, and $2.18 billion, respectively, of which fee-based revenues constituted 82%, 75% and 77%, respectively, and non-fee based margin constituted 18%, 25% and 23%, respectively. The amount of segment margin earned by ETO’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.
ETO’s revenues depend on its customers’ ability to use ETO’s pipelines and third-party pipelines over which we have no control.
ETO’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 ETO. 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 ETO’s ability, and the ability of its customers, to transport natural gas to and from ETO’s pipelines and facilities and a corresponding material adverse effect on its transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from ETO’s facilities affect the utilization and value of ETO’s 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.

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Shippers using ETO’s oil pipelines and terminals are also dependent upon ETO’s 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 ETO’s pipelines or through its terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to ETO existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in ETO’s pipelines or through its 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 ETO’s results of operations, financial position, or cash flows.
If ETO does not continue to construct new pipelines, its future growth could be limited.
ETO’s results of operations and its ability to grow and to increase distributable cash flow per unit will depend, in part, on ETO’s ability to construct pipelines that are accretive to its distributable cash flow. ETO 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 ETO 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 ETO’s business by constructing new pipelines and related facilities subjects ETO to risks.
One of the ways that ETO has grown its 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 ETO’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 ETO undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. A variety of factors outside ETO’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 ETO’s results of operations and cash flows. Moreover, revenues may not increase immediately following the completion of a particular project. For instance, if ETO builds a new pipeline, the construction will occur over an extended period of time, but ETO 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 ETO’s ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, ETO 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 ETO’s expected investment return, which could adversely affect its results of operations and financial condition.
ETO depends on certain key producers for our supply of natural gas and the loss of any of these key producers could adversely affect ETO’s financial results.
ETO relies on a limited number of producers for a significant portion of its natural gas supplies. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, ETO will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. ETO 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 ETO’s business, results of operations, and financial condition.
ETO depends on key customers to transport natural gas through its pipelines.
ETO relies on a limited number of major shippers to transport certain minimum volumes of natural gas on its pipelines. The failure of the major shippers on ETO’s or its 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, ETO or its joint ventures, as applicable. If ETO were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts, it could have a material adverse effect on results of operations.

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ETO’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 substantial majority of the components for ETO’s natural gas compression equipment are supplied by Caterpillar Inc., Cummins Inc. and Arrow Engine Company for engines, Air-X-Changers and Alfa Laval (US) for coolers, and Ariel Corporation, GE Oil & Gas Gemini products and Arrow Engine Company for compressor frames and cylinders. ETO’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. ETO also relies primarily on four vendors, A G Equipment Company, Alegacy Equipment, LLC, Standard Equipment Corp. and Genis Holdings LLC, to package and assemble its compression units. ETO does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of any of these sources could have a negative impact on its results of operations and could damage its customer relationships. Some of these suppliers manufacture the components ETO purchases in a single facility, and any damage to that facility could lead to significant delays in delivery of completed compression units to ETO.
A material decrease in demand or distribution of crude oil available for transport through ETO’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 ETO’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 ETO’s customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported in ETO’s crude oil pipelines and terminal facilities could decline, and it could be difficult to secure alternative sources of attractively priced crude oil supply in a timely fashion or at all. If ETO 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.
Shifts in the overall supply of, and demand for, crude oil in regional, national and global markets, over which we have no control, can have an adverse impact on crude oil index prices in the markets we serve relative to other index prices. A prolonged decline in the WTI Index price, relative to other index prices, may cause reduced demand for our transportation to, and storage in, Cushing, which could have a material adverse effect on our business, results of operations and financial condition.
An interruption of supply of crude oil to ETO’s facilities could materially and adversely affect our results of operations and revenues.
While ETO 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 ETO 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 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 ETO’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.
ETO 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 ETO 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 ETO to a risk of loss or misuse of this information, result in litigation and potential liability for ETO, lead to reputational damage, increase compliance costs, or otherwise harm its business.

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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, ETO’s subsidiary, serves would reduce their ability to make distributions to its unitholders.
Sales of refined motor fuels account for approximately 97% of Sunoco LP’s total revenues and 74% 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 distributions to its 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 its unitholders.
The industries in which Sunoco LP, ETO’s subsidiary, 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 its 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

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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 its 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 its 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 its 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 its 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.

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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 its unitholders.
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 its 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.
USAC’s customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own or using alternative technologies for enhancing crude oil production.
USAC’s customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using USAC’s compression services. The historical availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable to USAC's customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and USAC's customers may elect to use these alternative technologies instead of the gas lift compression services USAC provides. Such vertical integration, increases in vertical integration or use of alternative technologies could result in decreased demand for USAC's compression services, which may have a material adverse effect on its business, results of operations, financial condition and reduce its cash available for distribution.
A significant portion of USAC's services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue to utilize its services.
USAC's contracts typically have an initial term of between six months and five years, depending on the application and location of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by USAC or USAC's customers upon notice as provided for in the applicable contract. For the year ended December 31, 2019, approximately 36% of USAC's compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize its services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on USAC's business, results of operations, financial condition and cash available for distribution.

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USAC’s Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.
USAC’s Preferred Units rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for its common units, or could make it more difficult for USAC to sell its common units in the future.
In addition, distributions on USAC’s Preferred Units accrue and are cumulative, at the rate of 9.75% per annum on the original issue price, which amounts to a quarterly distribution of $24.375 per Preferred Unit. If USAC does not pay the required distributions on its Preferred Units, USAC will be unable to pay distributions on its common units. Additionally, because distributions on USAC’s Preferred Units are cumulative, USAC will have to pay all unpaid accumulated distributions on the Preferred Units before USAC can pay any distributions on its common units. Also, because distributions on USAC’s common units are not cumulative, if USAC does not pay distributions on its common units with respect to any quarter, USAC’s common unitholders will not be entitled to receive distributions covering any prior periods if USAC later recommences paying distributions on its common units.
USAC’s Preferred Units are convertible into common units by the holders of USAC’s Preferred Units or by USAC in certain circumstances. USAC’s obligation to pay distributions on USAC’s Preferred Units, or on the common units issued following the conversion of USAC’s Preferred Units, could impact USAC’s liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and other general Partnership purposes. USAC’s obligations to the holders of USAC’s Preferred Units could also limit its ability to obtain additional financing or increase its borrowing costs, which could have an adverse effect on its financial condition.
Changes in currency exchange rates could adversely affect our results of operations for our Canadian operations.
A portion of SemGroup’s revenue is generated from its operations in Canada, which use the Canadian dollar as the functional currency. Therefore, changes in the exchange rate between the U.S. dollar and the Canadian dollar could adversely affect SemGroup’s results of operations.
We are subject to the risks of doing business outside of the U.S.
The success of our business depends, in part, on continued performance in SemGroup’s non-U.S. operations. We currently have operations in Canada, which are expected to expand with SemGroup’s recent acquisition of Meritage Midstream and further organic growth. In addition to the other risks described in this report on Form 10-K, there are numerous risks and uncertainties that specifically affect our non-U.S. operations. These risks and uncertainties include political and economic instability, changes in local governmental laws, regulations and policies, including those related to tariffs, investments, taxation, exchange controls, employment regulations and repatriation of earnings, and enforcement of contract and intellectual property rights. International transactions may also involve increased financial and legal risks due to differing legal systems and customs, including risks of non-compliance with U.S. and local laws affecting our activities abroad, including compliance with the U.S. Foreign Corrupt Practices Act. While these factors and the impact of these factors are difficult to predict, any one or more of them could adversely affect our financial and operational results.
SemGroup’s trucking fleet operations are subject to the Federal Motor Carrier Safety Regulations which are enacted, reviewed and amended by the FMCSA. Our fleet currently has a "satisfactory" safety rating; however, if our safety rating were downgraded to "unsatisfactory," our business and results of operations could be adversely affected.
All federally regulated carriers’ safety ratings are measured through a program implemented by the FMCSA known as the Compliance Safety Accountability ("CSA") program. The CSA program measures a carrier's safety performance based on violations observed during roadside inspections as opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of comparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is a progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an "unsatisfactory" rating and the revocation of its operating authority by the FMCSA could have an adverse effect on our business, results of operations and financial condition.
Our storage operations are influenced by the overall forward market for crude oil and other products we store, and certain market conditions may adversely affect its financial and operating results.
Our storage operations are influenced by the overall forward market for crude oil and other products we store. A contango market (meaning that the price of crude oil or other products for future delivery is higher than the current price) is associated with greater demand for storage capacity, because a party can simultaneously purchase crude oil or other products at current prices for storage

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and sell at higher prices for future delivery. A backwardated market (meaning that the price of crude oil or other products for future delivery is lower than the current price) is associated with lower demand for storage capacity because a party can capture a premium for prompt delivery of crude oil or other products rather than storing it for future sale. A prolonged backwardated market, or other adverse market conditions, could have an adverse impact on its ability to negotiate favorable prices under new or renewing storage contracts, which could have an adverse impact on our storage revenues. As a result, the overall forward market for crude oil or other products may have an adverse effect on our financial condition or results of operations.
An increase in interest rates could impact demand for our storage capacity.
There is a financing cost for a storage capacity user to own crude oil while it is stored. That financing cost is impacted by the cost of capital or interest rate incurred by the storage user, in addition to the commodity cost of the crude oil in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing crude oil for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.
Increasing levels of congestion in the Houston Ship Channel could result in a diversion of business to less busy ports.
Our Gulf Coast facilities are strategically situated on prime real estate located in the Houston Ship Channel, which is in close proximity to both supply sources and demand sources. In recent years, the success of the Port of Houston has led to an increase in vessel traffic driven in part by the growing overseas demand for U.S. crude, gasoline, liquefied natural gas and petrochemicals and in part by the Port of Houston’s recent decision to accept large container vessels, which can restrict the flow of other cargo. Increasing congestion in the Port of Houston could cause our customers or potential customers to divert their business to smaller ports in the Gulf of Mexico, which could result in lower utilization of our facilities.
Increased regulation of hydraulic fracturing or produced water disposal could result in reductions or delays in crude oil and natural gas production in our areas of operation, which could adversely impact its business and results of operations.
The hydraulic fracturing process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies and may have other detrimental impacts on public health, safety, welfare and the environment. In addition, the water disposal process has come under scrutiny from sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. The adoption of new laws or regulations imposing additional permitting, disclosures, restrictions or costs related to hydraulic fracturing or produced water disposal or prohibiting hydraulic fracturing in proximity to areas considered to be environmentally sensitive could make drilling certain wells impossible or less economically attractive. As a result, the volume of crude oil and natural gas we gather, transport and store for our customers could be substantially reduced which could have an adverse effect on our financial condition or results of operations.
Competition for water resources or limitations on water usage for hydraulic fracturing could disrupt crude oil and natural gas production from shale formations.
Hydraulic fracturing is the process of creating or expanding cracks by pumping water, sand and chemicals under high pressure into an underground formation in order to increase the productivity of crude oil and natural gas wells. Water used in the process is generally fresh water, recycled produced water or salt water. There is competition for fresh water from municipalities, farmers, ranchers and industrial users. In addition, the available supply of fresh water can also be reduced directly by drought. Prolonged drought conditions increase the intensity of competition for fresh water. Limitations on oil and gas producers’ access to fresh water may restrict their ability to use hydraulic fracturing and could reduce new production. Such disruptions could potentially have a material adverse impact on our financial condition or results of operations.
ETO’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 ETO’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.
ETO 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. ETO 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

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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 ETO and find that its rates were not just and reasonable or unduly discriminatory, the maximum rates customers could elect to pay ETO may be reduced and the reduction could have an adverse effect on our revenues and results of operations.
The costs of ETO’s interstate pipeline operations may increase and ETO may not be able to recover all of those costs due to FERC regulation of its rates. If ETO 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 ETO’s proposed changes if ETO is unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. ETO 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 ETO may be constrained by competitive factors from charging their tariff rates.
To the extent ETO’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, ETO’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. ETO 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 ETO, 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. Effective January 2018, the 2017 Tax and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement because it is a non-binding policy and parties will have the opportunity to address the policy as applied in future cases. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs.
Included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. On July 18, 2018, the FERC issued a Final Rule (Order No. 849) adopting procedures that are generally the same as proposed in the NOPR with a few clarifications and modifications. With limited exceptions, the Final Rule requires all FERC-regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to make an election on how to treat its existing rates. The Final Rule suggests that this information will allow the FERC and other stakeholders to evaluate the impacts of the Tax Act and the Revised Policy Statement on each individual pipeline’s rates. The Final Rule also requires that each FERC-regulated natural gas pipeline select one of four options: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates only as required related to the Tax Act and the Revised Policy Statement, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. For the limited NGA Section 4 option, the FERC clarified that, notwithstanding the Revised Policy Statement, a pipeline organized as a master limited partnership does not need to eliminate its income tax allowance but, instead, can reduce its rates to reflect the reduction in the maximum corporate tax rate. Trunkline, ETC Tiger Pipeline, LLC and Panhandle filed their respective FERC Form No. 501-Gs on October 11, 2018. FEP, Lake Charles LNG and certain other operating subsidiaries filed their respective FERC Form No. 501-Gs on or about November 8, 2018. Rover, FGT, Transwestern and MEP filed their respective FERC Form No. 501-Gs on or about December 6, 2018. Because our existing jurisdictional rates were established based on a higher corporate tax rate, the FERC or our shippers may challenge these rates in the future, and the resulting new rate may be lower than the rates we currently charge. For example, the FERC has recently initiated reviews of Panhandle’s and Southwest Gas Storage Company’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged are just and reasonable.  These reviews will require the filing of a cost and revenue study prior to the FERC issuing a decision.
Rate regulation or market conditions may not allow ETO to recover the full amount of increases in the costs of its crude oil, NGL and refined products pipeline operations.
Transportation provided on ETO’s common carrier interstate crude oil, NGL and refined products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these pipelines be just and reasonable and not unduly

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discriminatory. If ETO 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 ETO’s ability to set rates based on its costs or may delay the use of rates that reflect increased costs. In October 2016, the FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (i) 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 percent for the prior two years; (ii) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5 percent above the barrel-mile cost changes; and (iii) 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. The 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 ETO’s financial condition, results of operations or cash flows.
Under the Energy Policy Act of 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of ETO’s 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 ETO 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 ETO’s business and results of operations.
State regulatory measures could adversely affect the business and operations of ETO’s midstream and intrastate pipeline and storage assets.
ETO’s midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects ETO’s business and the market for its products. The rates, terms and conditions of service for the interstate services ETO provides in its intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. ETO’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 ETO’s costs of service, its cash flow would be negatively affected.
ETO’s midstream and intrastate gas and oil transportation pipelines and its intrastate gas storage operations are subject to state regulation. All of the states in which we 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 ETO 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, ETO’s businesses may be adversely affected.
ETO’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.
ETO 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.

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Certain of ETO’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 NGL 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 the 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 the 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 the 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.
ETO may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to authority under the NGPSA and HLPSA, 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

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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. In 2018, PHMSA announced its intention to divide the original proposed rulemaking into three parts and issue three separate final rulemakings in 2019. In October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines, and enhanced emergency order procedures. The gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming MAOP. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA is expected to issue the second and third parts of the gas Mega Rule in the near future. The safety and hazardous liquid pipelines rule would extend leak detection requirements to all non-gathering hazardous liquid pipelines and require operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. Finally, the enhanced emergency procedures rule focuses on increased emergency safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety. The changes adopted or proposed by these rulemakings or made in future legal requirements could have a material adverse effect on ETO’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. In July 2019, PHMSA issued a final rule increasing the maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $218,647 per day, with a maximum of $2,186,465 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, which were issued in January 2020. 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. In 2018, PHMSA announced its intention to divide the original proposed rulemaking into three parts and issue three separate final rulemakings in 2019. In October 2019, PHMSA submitted the first of the three parts of the so-called gas Mega Rule to the Federal Register. That rule, application to gas transmission pipelines, requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming MAOP. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. This rule will take effect on July 1, 2020. PHMSA is then expected to issue the second part of the Mega Rule focusing on repair criteria in HCAs and creating new repair criteria for non-HCAs, requirements for inspecting pipelines following extreme events, updates to pipeline corrosion control requirements, and various other integrity management requirements. PHMSA is expected to subsequently issue the final part of the gas Mega Rule, the Gas Gathering Rule, focusing on requirements relating to gas gathering lines. 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 us 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 our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial condition.
ETO’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 ETO to incur significant costs and liabilities.
ETO’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 ETO’s pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from ETO’s construction and operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to enforce

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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 action 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.
ETO 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 ETO’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.” The EPA finalized its non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in April and July 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 ETO’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 ETO’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, ETO 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.
Regulations under the Clean Water Act, OPA and state laws impose regulatory burdens on terminal operations. Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks. The Clean Water Act also requires ETO to maintain spill prevention control and countermeasure plans at ETO’s terminal facilities with above-ground storage tanks and pipelines. In addition, OPA requires that most fuel transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. Facilities that are adjacent to water require the engagement of Federally Certified Oil Spill Response Organizations (“OSRO”s) to be available to respond to a spill on water from above-ground storage tanks or pipelines.
Transportation and storage of refined products over and adjacent to water involves risk and potentially subjects ETO to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon ETO. The Clean Water Act imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters, with the potential of substantial liability for the violation of permits or permitting requirements.
Terminal operations and associated facilities are subject to the Clean Air Act as well as comparable state and local statutes. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources that are already constructed. If regulations become more stringent, additional emission control technologies
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, ETC Sunoco is a defendant in numerous lawsuits that allege

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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 ETC Inc. could have a material adverse effect on our business or results of operations.
Climate change legislation or regulations restricting emissions of GHGs 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 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. In September 2018, the EPA proposed amendments to Subpart OOOOa that would reduce the 2016 standards’ fugitive emissions monitoring requirements and expand exceptions to controlling methane emissions from pneumatic pumps, among other changes. Various industry and environmental groups have separately challenged both the original 2016 standards and the EPA’s attempts to delay the implementation of the rule. In August 2019, the EPA proposed two options for further rescinding the Subpart OOOOa standards. Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for volatile organic compounds, or VOCs, and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources. In addition, the proposal would remove from the oil and natural gas category the natural gas transmission and storage segment. The other proposed alternative would rescind the methane requirements of the Subpart OOOOa standards applicable to all oil and natural gas sources, without removing any sources from that source category (and still requiring control of VOCs in general). 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 ETO’s operations as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect ETO’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 United States formally initiated the withdrawal process in November 2019, 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

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have a material adverse effect on ETO’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 ETO’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 ETO’s operations and otherwise materially adversely affect its cash flow.
Some of ETO’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. Virtually all of ETO’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.

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If one or more facilities that are owned by ETO or that deliver natural gas or other products to ETO are damaged by severe weather or any other disaster, accident, catastrophe or event, ETO’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETO’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 ETO’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETO’s cash available for distributions to 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, ETO may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETO were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETO’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 ETO’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 ETO’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, development, oil spill-response and decommissioning plans, and other related developments may have a material adverse effect on our business, financial condition, or results of operations.
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 ETO’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 ETO’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

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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 ETO’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 ETO’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 ETO’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 patented 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 unionized employees.
As of December 31, 2019, approximately 12% 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 we 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.
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.

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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, our wholly-owned subsidiary, is in the process of developing a liquefaction project at the site of our existing regasification facility in Lake Charles, Louisiana. The project development agreement previously entered into in September 2013 with BG Group plc, a subsidiary of 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 us 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 original FERC order issued on December 17, 2015 authorized LCL to site, construct and operate the liquefaction project, subject to a a condition requiring all phases of the liquefaction project to be completed and in-service within five years of the date of the order. The order also required the modifications to our Trunkline pipeline facilities that connect to our Lake Charles facility be complete by December 17, 2019 and additionally requires execution of a transportation contract for natural gas supply to the liquefaction facility prior to the initiation of construction of the liquefaction facility. In December 2019, LCL received an extension of these completion dates for the project to December 2025. There can be no assurances that these projects will be completed prior to the new construction deadlines.
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

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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, our 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, ETO or its subsidiaries, including Sunoco LP and USAC as a corporation for federal income tax purposes or if we, ETO, Sunoco LP or USAC 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 ETO and its subsidiaries, including Sunoco LP and USAC, depend largely on ETO, Sunoco LP and USAC being treated as partnerships for federal income tax purposes. Despite the fact that we, ETO, Sunoco LP and USAC 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, ETO, Sunoco LP and USAC satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us, ETO, Sunoco LP or USAC to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we, ETO, Sunoco LP or USAC 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

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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.
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.
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

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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 finalized.  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

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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

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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; Houston, Texas 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 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. We 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 pipelines were built were purchased in fee. We also own and operate multiple natural gas and NGL storage facilities and own or lease other processing, treating and conditioning facilities in connection with our midstream operations.
ITEM 3. LEGAL PROCEEDINGS
ETC Sunoco Holdings LLC and Sunoco (R&M), LLC (collectively, “Sunoco”) are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive business practices claims. 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, 2019, Sunoco is a defendant in five cases, including one case each initiated by the States of Maryland and 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 ETO, ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals L.P. (“SPMT”).
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 October 2016, PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETO’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The case went to hearing in March 2017. On November 14, 2019, PHMSA issued a Final Order that upheld the two alleged violations and resultant civil penalty in the amount of $251,800.  The full payment was made on November 27, 2019, and the case is now closed.
In April 2016, PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain welding practices and procedures followed during construction of ETO’s Permian Express 2 pipeline system in Texas.  The case went to hearing before an Administrative Hearing Officer in November 2016. Recently, PHMSA issued a Final Order withdrawing two of the five alleged violations and resulting in a reduction of the civil penalty from $1,278,100 to $882,600 along with ordering compliance actions.
In July 2016, PHMSA issued a NOPV, PCO and proposed civil penalty 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 case went to hearing in March 2017.  The Proposed Compliance Order was fully withdrawn.  On November 8, 2019, PHMSA issued a Final Order that

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withdrew three alleged violations and reduced the civil penalty from $1,539,800 to $1,019,200.  The full payment was made on December 9, 2019 and the case is now closed.
In late 2016, FERC Enforcement Staff began a non-public investigation of Rover’s removal 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. In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigations. Enforcement Staff has provided Rover its non-public preliminary findings regarding those investigations. The company disagrees with those findings and intends to vigorously defend against any potential penalty. Given the stage of the proceedings, and the non-public nature of the investigation, the Partnership is unable at this time to provide an assessment of the potential outcome or range of potential liability, if any.
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants (collectively, the “Defendants”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019, the Fifth District court of appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court, which Defendants intend to oppose.
Energy Transfer Company Field Services received NOV REG-0569-1701 on June 6, 2017 for emission events that occurred January 1, 2017 through April 16, 2017 at the Jal 3 gas plant. On September 11, 2017, the New Mexico Environmental Department sent ETO a settlement offer to resolve the NOV for a penalty of $596,278. Negotiations for this settlement offer are ongoing.
Energy Transfer Company Field Services received NOV REG-0569-1702 on December 8, 2017 for emission events that occurred April 17, 2017 through September 23, 2017 at the Jal 3 gas plant. On January 31, 2018, ETO received a settlement offer to resolve the NOV for a penalty of $602,138. Negotiations for this settlement offer are ongoing.
Energy Transfer Company Field Services received NOV REG-0569-1801 on February 13, 2018 for emission events that occurred September 25, 2017 through December 29, 2017 at the Jal 3 gas plant. On June, 11, 2018, the New Mexico Environmental Department sent ETO a settlement offer to resolve the NOV for a penalty of $268,213. Negotiations for this settlement offer are ongoing.
In June 2018, ETC Northeast Pipeline LLC (“ETC Northeast”) entered into a Consent Order and Agreement with the PADEP, pursuant to which ETC Northeast agreed to pay $150,242 to the PADEP to settle various statutory and common law claims relating to soil discharge into, and erosion of the stream bed of, Raccoon Creek in Center Township, Pennsylvania during construction of the Revolution Pipeline. ETC Northeast has paid the settlement amount and continues to monitor the construction site and work with the landowner to resolve any remaining issues related to the restoration of the construction site.
Energy Transfer Company Field Services received NOV REG-0569-1802 from the New Mexico Environmental Department on July 25, 2018 for emission events that occurred January 1, 2018 through April 30, 2018 at the Jal 3 gas plant. On September 25, 2018, ETO received a settlement offer to resolve the NOV for a penalty of $1,151,499. Negotiations for this settlement offer are ongoing.
Energy Transfer Field Company Services received NOV REG-0569-1803 from the New Mexico Environmental Department on November 8, 2018 for emission events that occurred May 1, 2018 through August 31, 2018 at the Jal 3 gas plant. On December 28, 2018, ETO received a settlement offer to resolve the NOV for a penalty of $1,405,652. Negotiations for this settlement offer are ongoing.
In January 2019, we received notice from the DOJ on behalf of the EPA that a civil penalty enforcement action was being pursued under the Clean Water Act for an estimated 450 barrel crude oil release from the Mid-Valley Pipeline operated by SPLP and owned by Mid-Valley Pipeline Corporation. The release purportedly occurred in October 2014 on a nature preserve located in Hamilton County, Ohio, near Cincinnati, Ohio. After discovery and notification of the release, SPLP conducted substantial emergency response, remedial work and primary restoration in three phases and the primary restoration has been acknowledged to be complete. Operation and maintenance (O&M) activities will continue for several years. In December of 2019, SPLP reached an agreement in principal with the EPA regarding payment of a civil penalty which will be subject to public comment. The DOJ, on behalf of United States Department of Interior Fish and Wildlife, and the Ohio Attorney General, on behalf of the Ohio EPA, along with technical representatives from those agencies have been discussing natural resource damage assessment claims related to state endangered species and compensatory restoration. The timing and 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.
On September 10, 2018, a pipeline release and fire (the “Incident”) occurred on the Revolution pipeline, a natural gas gathering line located in Center Township, Beaver County, Pennsylvania. There were no injuries. On February 8, 2019, the Pennsylvania

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Department of Environmental Protection (“PADEP”) issued a Permit Hold on any requests for approvals/permits or permit amendments for any project in Pennsylvania pursuant to the state’s water laws. The Partnership filed an appeal of the Permit Hold with the Pennsylvania Environmental Hearing Board. On January 3, 2020, the Partnership entered into a Consent Order and Agreement with the Department in which, among other things, the Permit Hold was lifted, the Partnership agreed to pay a $28.6 million civil penalty and fund a $2 million community environmental project, and all related appeals were withdrawn.
The Pennsylvania Office of Attorney General has commenced an investigation regarding the Incident, and the United States Attorney for the Western District of Pennsylvania has issued a federal grand jury subpoena for documents relevant to the Incident. The scope of these investigations is not further known at this time.
On June 4, 2019, the Oklahoma Corporation Commission’s (“OCC”) Transportation Division filed a complaint against SPLP seeking a penalty of up to $1 million related to a May 2018 rupture near Edmond, Oklahoma.  The rupture occurred on the Noble to Douglas 8” pipeline in an area of external corrosion and caused the release of approximately fifteen barrels of crude oil. SPLP responded immediately to the release and remediated the surrounding environment and pipeline in cooperation with the OCC.  The OCC filed the complaint alleging that SPLP failed to provide adequate cathodic protection to the pipeline causing the failure.  SPLP is negotiating a settlement agreement with the OCC for a lesser penalty.
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.

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PART II
ITEM 5.  MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Parent Company
Description of Units
As of February 14, 2020, there were approximately 590,000 registered common unitholders, which includes common units held in street name. Common units represent limited partner interests 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, 2019, limited partners own an aggregate 99.9% limited partner interest in us. Our General Partner owns an aggregate 0.1% 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 under the ticker symbol “ET.” 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.”
ET Class A Units
In connection with the Energy Transfer Merger, the Partnership issued 647,745,099 Class A units (“ET Class A Units”) representing limited partner interests in the Partnership to the General Partner. The number of ET Class A Units issued allows the General Partner and its affiliates to retain a voting interest in the Partnership that is identical to their voting interest in the Partnership prior to the completion of the Energy Transfer Merger. The ET Class A Units are entitled to vote together with the Partnership’s common units, as a single class, except as required by law. Additionally, ET’s partnership agreement provides that, under certain circumstances, upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to any holder of ET Class A Units additional ET Class A Units such that the holder maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance of common units. In connection with the SemGroup Transaction, we issued an additional 14,246,973 ET Class A Units in December 2019. The ET Class A Units are not entitled to distributions and otherwise have no economic attributes.
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.

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Issuer Purchases of Equity Securities
The following table discloses purchases of ET Common Units made by us or on our behalf in the quarter ended December 31, 2019:
Period Total Number of Units Purchased Average Price Paid per Unit Total Number of Units Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Value of Units That May Yet be Purchased Under the Plans or Programs
October 2019 
 $
 
 
November 2019 
 
 
 
December 2019 1,916,795
 13.04
 1,916,795
 $910,831,303
Securities Authorized for Issuance Under Equity Compensation Plans
For information on the securities authorized for issuance under ET’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.
 Years Ended December 31,
 2019 2018 2017 2016 2015
Statement of Operations Data:         
Total revenues$54,213
 $54,087
 $40,523
 $31,792
 $36,096
Operating income7,277
 5,348
 2,721
 1,851
 2,287
Income from continuing operations4,899
 3,630
 2,543
 462
 1,023
Income (loss) from discontinued operations
 (265) (177) (462) 38
Net income4,899
 3,365
 2,366
 
 1,061
Basic income from continuing operations per limited partner unit1.37
 1.17
 0.86
 0.95
 1.11
Diluted income from continuing operations per limited partner unit1.36
 1.16
 0.84
 0.93
 1.11
Basic loss from discontinued operations per limited partner unit
 (0.01) (0.01) (0.01) 
Diluted loss from discontinued operations per limited partner unit
 (0.01) (0.01) (0.01) 
Cash distribution per common unit1.22
 1.22
 1.17
 1.14
 1.08
Balance Sheet Data (at period end):         
Assets held for sale
 
 3,313
 3,588
 3,681
Total assets98,880
 88,246
 86,246
 78,925
 71,144
Liabilities associated with assets held for sale
 
 75
 48
 42
Long-term debt, less current maturities51,028
 43,373
 43,671
 42,608
 36,837
Total equity33,845
 30,850
 29,980
 22,431
 23,553
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 LP is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ET.” ET was formed in September 2002 and completed its initial public offering in February 2006.

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The following discussion of our historical consolidated financial condition and results of operations 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 “ET” mean Energy Transfer LP and its consolidated subsidiaries, which include ETO, ETP GP, ETP LLC, Panhandle, Sunoco LP and Lake Charles LNG. References to the “Parent Company” mean Energy Transfer LP on a stand-alone basis.
OVERVIEW
Energy Transfer LP directly and indirectly owns equity interests in ETO, Sunoco LP and USAC, all of which are limited partnerships engaged in diversified energy-related services. Sunoco LP and USAC have publicly traded common units.
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 ETO. ETO’s earnings and cash flows are generated by its subsidiaries, including ETO’s investments in Sunoco LP and USAC. The amount of cash that ETO, Sunoco LP and USAC 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 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:
intrastate transportation and storage;
interstate transportation and storage;
midstream;
NGL and refined products transportation and services;
crude oil transportation and services;
investment in Sunoco LP;
investment in USAC; and
all other.
The general partner of ETO has separate operating management and boards of directors. We control ETO through our owner ship of its respective general partners.
Recent Developments
ETO Series F and Series G Preferred Units Issuance
On January 22, 2020, ETO issued 500,000 of its 6.750% Series F Preferred Units at a price of $1,000 per unit and 1,100,000 of its 7.125% Series G Preferred Units at a price of $1,000 per unit. The net proceeds were used to repay amounts outstanding under ETO’s revolving credit facility and for general partnership purposes.
ETO January 2020 Senior Notes Offering and Redemption
On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of ETO’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of ETO’s 3.750% Senior Notes due 2030, and $2.00 billion aggregate principal amount of ETO’s 5.000% Senior Notes due 2050, (collectively, the “Notes”).

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The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis.
Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.
ETO Term Loan
On October 17, 2019, ETO entered into a term loan credit agreement (the “ETO Term Loan”) providing for a $2.00 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P.
As of December 31, 2019, the ETO Term Loan had $2.00 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2019 was 2.78%.
SemGroup Acquisition and ET Contribution of SemGroup Assets to ETO
On December 5, 2019, ET completed the acquisition of SemGroup pursuant to the terms of the Agreement and Plan of Merger, dated as of September 15, 2019 (the “Merger Agreement”). Under the terms of the Merger Agreement, a wholly owned subsidiary of ET merged with and into SemGroup (the “SemGroup Transaction”), with SemGroup surviving the Merger. At the effective time of the SemGroup Transaction on December 5, 2019, each share of class A common stock, par value $0.01 per share, of SemGroup issued and outstanding immediately prior to the effective time was converted into the right to receive (i) $6.80 in cash, without interest, and (ii) 0.7275 ET Common Units representing limited partner interests in ET. Each share of Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.01 per share, of SemGroup that was issued and outstanding as of immediately prior to the effective time was redeemed by SemGroup for cash at a price per share equal to 101% of the liquidation preference.
During the first quarter of 2020, ET contributed certain SemGroup assets to ETO through sale and contribution transactions.
JC Nolan Pipeline
On July 1, 2019, ETO and Sunoco LP entered into a joint venture on the JC Nolan diesel fuel pipeline to West Texas and the JC Nolan terminal. ETO operates the pipeline for the joint venture, which transports diesel fuel from Hebert, Texas to a terminal in the Midland, Texas area. The diesel fuel pipeline has an initial capacity of 30,000 barrels per day and was successfully commissioned in August 2019.
Series E Preferred Units Issuance
In April 2019, ETO issued 32 million of its 7.600% Series E Preferred Units at a price of $25 per unit, including 4 million Series E Preferred Units pursuant to the underwriters’ exercise of their option to purchase additional preferred units. The total gross proceeds from the Series E Preferred Unit issuance were $800 million, including $100 million from the underwriters’ exercise of their option to purchase additional preferred units. The net proceeds were used to repay amounts outstanding under ETO’s revolving credit facility and for general partnership purposes.
ET-ETO Senior Notes Exchange
In March 2019, ETO issued approximately $4.21 billion aggregate principal amount of senior notes to settle and exchange approximately 97% of ET’s outstanding senior notes. In connection with this exchange, ETO issued $1.14 billion aggregate principal amount of 7.50% senior notes due 2020, $995 million aggregate principal amount of 4.25% senior notes due 2023, $1.13 billion aggregate principal amount of 5.875% senior notes due 2024 and $956 million aggregate principal amount of 5.50% senior notes due 2027.
ETO 2019 Senior Notes Offering and Redemption
In January 2019, ETO issued $750 million aggregate principal amount of 4.50% senior notes due 2024, $1.50 billion aggregate principal amount of 5.25% senior notes due 2029 and $1.75 billion aggregate principal amount of 6.25% senior notes due 2049. The $3.96 billion net proceeds from the offering were used to repay in full ET’s outstanding senior secured term loan, to redeem outstanding senior notes, to repay a portion of the borrowings under the Partnership’s revolving credit facility and for general partnership purposes.

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Panhandle Senior Notes Redemption
In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.
Bakken Senior Notes Offering
In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, issued $650 million aggregate principal amount of 3.625% senior notes due 2022, $1.00 billion aggregate principal amount of 3.90% senior notes due 2024 and $850 million aggregate principal amount of 4.625% senior notes due 2029. The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.
Sunoco LP Senior Notes Offering
In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms.
USAC Senior Notes Offering
In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior notes due 2027 in a private placement, and in December 2019, USAC exchanged those notes for substantially identical senior notes registered under the Securities Act. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Rate Regulation
Effective January 2018, the 2017 Tax and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost of service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. In light of the rehearing order, the impacts of the FERC’s policy on the treatment of income taxes may have on the rates ETO can charge for the FERC-regulated transportation services are unknown at this time.
The FERC also issued a Notice of Inquiry (“2017 Tax Law NOI”) on March 15, 2018, requesting comments on the effect of the Tax Act on FERC jurisdictional rates. The 2017 Tax Law NOI states that of particular interest to the FERC is whether, and if so how, the FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments in response to the 2017 Tax Law NOI were due on or before May 21, 2018.
In March 2019, following the decision of the D.C. Circuit in Emera Maine v. Federal Energy Regulatory Commission, the FERC issued a Notice of Inquiry regarding its policy for determining return on equity (“ROE”). The FERC specifically sought information and stakeholder views to help the FERC explore whether, and if so how, it should modify its policies concerning the determination of ROE to be used in designing jurisdictional rates charged by public utilities. The FERC also expressly sought comment on whether any changes to its policies concerning public utility ROEs should be applied to interstate natural gas and oil pipelines. Initial comments were due in June 2019, and reply comments were due in July 2019. The FERC has not taken any further action with respect to the Notice of Inquiry as of this time, and therefore we cannot predict what effect, if any, such development could have on our cost-of-service rates in the future.

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Also included in the March 15, 2018 proposals is a Notice of Proposed Rulemaking (“NOPR”) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to natural gas pipeline rates. On July 18, 2018, the FERC issued a Final Rule adopting procedures that are generally the same as proposed in the NOPR with a few clarifications and modifications. With limited exceptions, the Final Rule requires all FERC-regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to make an election on how to treat its existing rates. The Final Rule suggests that this information will allow the FERC and other stakeholders to evaluate the impacts of the Tax Act and the Revised Policy Statement on each individual pipeline’s rates. The Final Rule also requires that each FERC-regulated natural gas pipeline select one of four options to address changes to the pipeline’s revenue requirements as a result of the tax reductions: file a limited Natural Gas Act (“NGA”) Section 4 filing reducing its rates to reflect the reduced tax rates, commit to filing a general NGA Section 4 rate case in the near future, file a statement explaining why an adjustment to rates is not needed, or take no other action. For the limited NGA Section 4 option, the FERC clarified that, notwithstanding the Revised Policy Statement, a pipeline organized as a master limited partnership does not need to eliminate its income tax allowance but, instead, can reduce its rates to reflect the reduction in the maximum corporate tax rate. Trunkline, ETC Tiger Pipeline, LLC and Panhandle filed their respective FERC Form No. 501-Gs on October 11, 2018. FEP, Lake Charles LNG and certain other operating subsidiaries filed their respective FERC Form No. 501-Gs on or about November 8, 2018, and Rover, FGT, Transwestern and MEP filed their respective FERC Form No. 501-Gs on or about December 6, 2018.
By order issued January 16, 2019, the FERC initiated a review of Panhandle’s existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Panhandle are just and reasonable and set the matter for hearing.  Panhandle filed a cost and revenue study on April 1, 2019. Panhandle filed a NGA Section 4 rate case on August 30, 2019.
By order issued October 1, 2019, the Panhandle Section 5 and Section 4 cases were consolidated. An initial decision is expected to be issued in the first quarter of 2021. By order issued February 19, 2019, the FERC initiated a review of Southwest Gas’ existing rates pursuant to Section 5 of the Natural Gas Act to determine whether the rates currently charged by Southwest Gas are just and reasonable and set the matter for hearing.  Southwest Gas filed a cost and revenue study on May 6, 2019.  On July 10, 2019, Southwest filed an Offer of Settlement in this Section 5 proceeding, which settlement was supported or not opposed by Commission Trial Staff and all active parties. The settlement was approved on October 29, 2019.
Sea Robin Pipeline Company filed a Section 4 rate case on November 30, 2018.  A procedural schedule was ordered with a hearing date in the 4th quarter of 2019.  Sea Robin Pipeline Company has reached a settlement of this proceeding, with a settlement filed July 22, 2019. The settlement was approved by the FERC by order dated October 17, 2019.
Even without action on the 2017 Tax Law NOI or as contemplated in the Final Rule, the FERC or our shippers may challenge the cost of service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of just and reasonable cost of service rates. Although changes in these two tax related components may decrease, other components in the cost of service rate calculation may increase and result in a newly calculated cost of service rate that is the same as or greater than the prior cost of service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost of service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger Pipeline, LLC, MEP and FEP, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. We do not expect market-based rates, negotiated rates or discounted rates that are not tied to the cost of service rates to be affected by the Revised Policy Statement or any final regulations that may result from the March 15, 2018 proposals. The revenues we receive from natural gas transportation services we provide pursuant to cost of service based rates may decrease in the future as a result of the ultimate outcome of the NOI, the Final Rule, and the Revised Policy Statement, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost of service rates, if any, will depend on a detailed review of all of ETO’s cost of service components and the outcomes of any challenges to our rates by the FERC or our shippers.
Pipeline Certification
The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of 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. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or before July 25, 2018. We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.

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Interstate Common Carrier Regulation
The FERC utilizes 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, or PPI. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. Many existing pipelines utilize the FERC liquids index to change transportation rates annually every July 1. With respect to liquids and refined products pipelines subject to FERC jurisdiction, the Revised Policy Statement requires the pipeline to reflect the impacts to its cost of service from the Revised Policy Statement and the Tax Act on Page 700 of FERC Form No. 6. This information will be used by the FERC in its next five year review of the liquids pipeline index to generate the index level to be effective July 1, 2021, thereby including the effect of the Revised Policy Statement and the Tax Act in the determination of indexed rates prospectively, effective July 1, 2021. The FERC’s establishment of a just and reasonable rate, including the determination of the appropriate liquids pipeline index, is based on many components, and tax related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect the FERC’s determination of the appropriate pipeline index. Accordingly, depending on the FERC’s application of its indexing rate methodology for the next five year term of index rates, the Revised Policy Statement and tax effects related to the Tax Act may impact our revenues associated with any transportation services we may provide pursuant to cost of service based rates in the future, including indexed rates.
Trends and Outlook
We continue to evaluate and execute strategies to enhance unitholder value through growth, as well as the integration and optimization of our diversified asset portfolio. We intend to target a minimum distribution coverage ratio of 1.50x, thereby promoting a prudent balance between distribution rates and enhanced financial flexibility and strength while maintaining our investment grade ratings. We anticipate continued earnings growth in 2020 from the recently completed projects, as well as our current project backlog. We also continue to seek asset optimization opportunities through strategic transactions among us and our subsidiaries and/or affiliates, and we expect to continue to evaluate and execute on such opportunities. As we have in the past, we will evaluate growth projects and acquisitions as such opportunities may be identified in the future, and we believe that the current capital markets are conducive to funding such future projects.
With respect to commodity prices, natural gas prices have remained comparatively low in recent months as associated gas from shale oil resources has provided additional supply to the market, increasing domestic supply to highs above 100 Bcf/d. Global oil and natural gas demand growth is likely to continue into the foreseeable future and will support U.S. production increases and, in turn U.S. natural gas export projects to Mexico as well as LNG exports.
For crude oil, new pipelines that came online during 2019 have resulted in Permian barrels now pricing closer to other regional hubs, which is a departure from the substantial discounts seen a year ago. These pipelines have enabled Permian producers to realize higher crude oil revenues, supporting continued growth in the region. Crude oil exports from the U.S. are continuing to increase as a result, providing additional opportunity for U.S. midstream sector growth.
Results of Operations
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total Partnership 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, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.  The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled “Segment Operating Results.” Adjusted EBITDA 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

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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.
Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018
Consolidated Results
 Years Ended December 31,  
 2019 2018 Change
Segment Adjusted EBITDA:     
Intrastate transportation and storage$999
 $927
 $72
Interstate transportation and storage1,792
 1,680
 112
Midstream1,602
 1,627
 (25)
NGL and refined products transportation and services2,666
 1,979
 687
Crude oil transportation and services2,972
 2,330
 642
Investment in Sunoco LP665
 638
 27
Investment in USAC420
 289
 131
All other98
 40
 58
Total Segment Adjusted EBITDA11,214
 9,510
 1,704
Depreciation, depletion and amortization(3,147) (2,859) (288)
Interest expense, net of interest capitalized(2,331) (2,055) (276)
Impairment losses(74) (431) 357
Gains (losses) on interest rate derivatives(241) 47
 (288)
Non-cash compensation expense(113) (105) (8)
Unrealized losses on commodity risk management activities(5) (11) 6
Inventory valuation adjustments79
 (85) 164
Losses on extinguishments of debt(18) (112) 94
Adjusted EBITDA related to unconsolidated affiliates(626) (655) 29
Equity in earnings of unconsolidated affiliates302
 344
 (42)
Adjusted EBITDA related to discontinued operations
 25
 (25)
Other, net54
 21
 33
Income from continuing operations before income tax expense5,094
 3,634
 1,460
Income tax expense from continuing operations(195) (4) (191)
Income from continuing operations4,899
 3,630
 1,269
Loss from discontinued operations, net of income taxes
 (265) 265
Net income$4,899
 $3,365
 $1,534
Adjusted EBITDA (consolidated). For the year ended December 31, 2019 compared to the prior year, Adjusted EBITDA increased approximately $1.7 billion, or 18%. The increase was primarily due to the impact of multiple revenue-generating assets being placed in service and recent acquisitions, as well as increased demand for services on existing assets. The impact of new assets and acquisitions was approximately $784 million, of which the largest increases were from increased volumes to our Mariner East pipeline and terminal assets due to the addition of pipeline capacity in the fourth quarter of 2018 (a $274 million impact to the NGL and refined products transportation and services segment), the commissioning of our fifth and sixth fractionators (a $131 million impact to the NGL and refined products transportation and services segment), the ramp up of volumes on our Bayou Bridge system due to placing phase II in service in the second quarter of 2019 (a $60 million impact to our crude oil transportation and services segment), the Rover pipeline (a $78 million impact to the interstate transportation and storage segment), the addition of gas processing capacity to our Arrowhead gas plant (a $31 million impact to our midstream segment), placing our Permian Express 4 pipeline in service in October 2019 (a $26 million impact to our crude oil transportation and services segment) and the acquisition of USAC (a net impact of $131 million among the investment in USAC and all other segments). The remainder of the increase in Adjusted EBITDA was primarily due to stronger demand on existing assets, particularly due to increased throughput on our Bakken Pipeline system as well as increased production in the Permian, which impacted multiple segments. Additional discussion of these

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and other factors affecting Adjusted EBITDA is included in the analysis of Segment Adjusted EBITDA in the “Segment Operating Results” section below.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased primarily due to additional depreciation from assets recently placed in service and recent acquisitions.
Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased primarily due to the following:
an increase of $198 million recognized by the Partnership (excluding Sunoco LP and USAC, which are discussed below) primarily due to increases in ETO’s long-term debt;
an increase of $49 million recognized by USAC primarily attributable to higher overall debt balances and higher interest rates on borrowings under the credit agreement. These increases were partially offset by the decrease in borrowings under the credit agreement; and
an increase of $29 million recognized by Sunoco LP due to an increase in total long-term debt; offset by
Impairment Losses. During the year ended December 31, 2019, the Partnership recognized goodwill impairments of $12 million related to the Southwest Gas operations within the interstate transportation and storage segment and $9 million related to our North Central operations within the midstream segment, both of which were primarily due to changes in assumptions related to projected future revenues and cash flows. Also during the year ended December 31, 2019, Sunoco LP recognized a $47 million write-down on assets held for sale related to its ethanol plant in Fulton, New York, and USAC recognized a $6 million fixed asset impairment related to certain idle compressor assets.
During the year ended December 31, 2018, the Partnership recognized goodwill impairments of $378 million and asset impairments of $4 million related to our midstream operations and asset impairments of $9 million related to idle leased assets in our crude operations. Sunoco LP recognized a $30 million indefinite-lived intangible asset impairment related to contractual rights. USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets. Additional discussion on these impairments is included in “Estimates and Critical Accounting Policies” below.
Gains (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, 2019 resulted from a decrease in forward interest rates and gains in 2018 resulted from an increase in forward interest rates.
Unrealized Gains (Losses) on Commodity Risk Management Activities.  The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships.  Information on the unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and in Note 13 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Inventory Valuation Adjustments. Inventory valuation reserve adjustments were recorded for the inventory associated with Sunoco LP primarily driven by changes in fuel prices between periods.
Losses on Extinguishments of Debt. Amounts were related to Sunoco LP’s senior note and term loan redemption in January 2018.
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 were disposed of in January 2018.
Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.
Income Tax Expense. For the year ended December 31, 2019 compared to the same period in the prior year, income tax expense increased due to an increase in income before tax expense at our corporate subsidiaries and the recognition of a favorable state tax rate change in the prior period.

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Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
 Years Ended December 31,  
 2019 2018 Change
Equity in earnings of unconsolidated affiliates:     
Citrus$148
 $141
 $7
FEP59
 55
 4
MEP15
 31
 (16)
Other80
 117
 (37)
Total equity in earnings of unconsolidated affiliates$302
 $344
 $(42)
      
Adjusted EBITDA related to unconsolidated affiliates(1):
     
Citrus$342
 $337
 $5
FEP75
 74
 1
MEP60
 81
 (21)
Other149
 163
 (14)
Total Adjusted EBITDA related to unconsolidated affiliates$626
 $655
 $(29)
      
Distributions received from unconsolidated affiliates:     
Citrus$178
 $171
 $7
FEP73
 68
 5
MEP36
 48
 (12)
Other101
 110
 (9)
Total distributions received from unconsolidated affiliates$388
 $397
 $(9)
(1) 
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments.
The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows:
Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment.
Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure.
Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure.
Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have

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control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.
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. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.
In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin, and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
For additional information regarding our business segments, see “Item 1. Business” and Notes 1 and 16 to our consolidated financial statements in “Item 8. Financial Statements and Supplementary Data.”
Segment Operating Results
Intrastate Transportation and Storage
 Years Ended December 31,  
 2019 2018 Change
Natural gas transported (BBtu/d)12,442
 10,873
 1,569
Revenues$3,099
 $3,737
 $(638)
Cost of products sold1,909
 2,665
 (756)
Segment margin1,190
 1,072
 118
Unrealized losses on commodity risk management activities2
 38
 (36)
Operating expenses, excluding non-cash compensation expense(190) (189) (1)
Selling, general and administrative expenses, excluding non-cash compensation expense(29) (27) (2)
Adjusted EBITDA related to unconsolidated affiliates25
 32
 (7)
Other1
 1
 
Segment Adjusted EBITDA$999
 $927
 $72
Volumes.  For the year ended December 31, 2019 compared to the prior year, transported volumes increased primarily due to the impact of reflecting RIGS as a consolidated subsidiary beginning April 2018 and the impact of the Red Bluff Express pipeline coming online in May 2018, as well as the impact of favorable market pricing spreads.
Segment Margin.  The components of our intrastate transportation and storage segment margin were as follows:
 Years Ended December 31,  
 2019 2018 Change
Transportation fees$614
 $525
 $89
Natural gas sales and other (excluding unrealized gains and losses)505
 510
 (5)
Retained fuel revenues (excluding unrealized gains and losses)50
 59
 (9)
Storage margin, including fees (excluding unrealized gains and losses)23
 16
 7
Unrealized losses on commodity risk management activities(2) (38) 36
Total segment margin$1,190
 $1,072
 $118

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Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:
an increase of $64 million in transportation fees, excluding the impact of consolidating RIGS beginning April 2018 as discussed below, primarily due to the Red Bluff Express pipeline coming online in May 2018, as well as new contracts;
a net increase of $11 million primarily due to the consolidation of RIGS beginning April 2018, resulting in increases in transportation fees, retained fuel revenues and operating expenses of $24 million, $2 million and $6 million, respectively, partially offset by a decrease in Adjusted EBITDA related to unconsolidated affiliates of $9 million; and
an increase of $7 million in realized storage margin primarily due to a realized adjustment to the Bammel storage inventory of $25 million in 2018 and higher storage fees, partially offset by a $20 million decrease due to lower physical withdrawals; partially offset by
a decrease of $9 million in retained fuel revenues primarily due to lower gas prices; and
a decrease of $5 million in realized natural gas sales and other due to lower realized gains from pipeline optimization activity.
Interstate Transportation and Storage
 Years Ended December 31,  
 2019 2018 Change
Natural gas transported (BBtu/d)11,346
 9,542
 1,804
Natural gas sold (BBtu/d)17
 17
 
Revenues$1,963
 $1,682
 $281
Operating expenses, excluding non-cash compensation, amortization and accretion expenses(569) (431) (138)
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses(72) (63) (9)
Adjusted EBITDA related to unconsolidated affiliates477
 492
 (15)
Other(7) 
 (7)
Segment Adjusted EBITDA$1,792
 $1,680
 $112
Volumes. For the year ended December 31, 2019 compared to the prior year, transported volumes increased as a result of the addition of new contracted volumes for delivery out of the Haynesville Shale, higher volumes on our Rover pipeline as a result of the full year availability of new supply connections, and higher throughput on Trunkline and Panhandle due to increased utilization of higher contracted capacity.
Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
an increase in margin of $231 million from the Rover pipeline due to higher reservation and usage resulting from additional connections and utilization of additional compression;
an increase of $40 million in reservation and usage fees due to improved market conditions allowing us to successfully bring new volumes to the system at improved rates, primarily on our Transwestern, Tiger and Panhandle Eastern systems; and
an increase of $6 million from the Sea Robin pipeline due to higher rates resulting from the rate case filed in June 2019, as well as fewer third party supply interruptions on the Sea Robin system; partially offset by
an increase of $138 million in operating expense primarily due to an increase in ad valorem taxes of $126 million on the Rover pipeline system resulting from placing the final portions of this asset into service in November 2018, an increase of $24 million in transportation expense on Rover due to an increase in transportation volumes, an increase of $5 million in allocated overhead costs and additional operating expense of $4 million for assets acquired in June 2019, partially offset by lower gas imbalance and system gas activity of $15 million and lower storage capacity leased on the Panhandle Eastern system of $8 million;
an increase of $9 million in selling, general and administrative expenses primarily due to an increase in insurance expense of $8 million, an increase in employee cost of $4 million, and an increase in allocated overhead costs of $3 million, partially offset by lower Ohio excise tax on our Rover system; and

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a decrease of $15 million in adjusted EBITDA related to unconsolidated affiliates primarily resulting from a $20 million decrease due to lower earnings from MEP as a result of lower capacity being re-contracted at lower rates on expiring contracts, partially offset by a $5 million increase from our Citrus joint venture as we brought new volumes to the system in 2019.
Midstream
 Years Ended December 31,  
 2019 2018 Change
Gathered volumes (BBtu/d)13,460
 12,126
 1,334
NGLs produced (MBbls/d)571
 540
 31
Equity NGLs (MBbls/d)31
 29
 2
Revenues$6,031
 $7,522
 $(1,491)
Cost of products sold3,577
 5,145
 (1,568)
Segment margin2,454
 2,377
 77
Operating expenses, excluding non-cash compensation expense(791) (705) (86)
Selling, general and administrative expenses, excluding non-cash compensation expense(90) (81) (9)
Adjusted EBITDA related to unconsolidated affiliates27
 33
 (6)
Other2
 3
 (1)
Segment Adjusted EBITDA$1,602
 $1,627
 $(25)
Volumes. For the year ended December 31, 2019 compared to the prior year, gathered volumes increased primarily due to increases in the Northeast, Permian, Ark-La-Tex, South Texas and North Texas regions. NGL production increased due to increases in the Permian and North Texas regions partially offset by ethane rejection in the South Texas region.
Segment Margin.  The table below presents the components of our midstream segment margin. For the year ended December 31, 2018, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect reclassification of certain contractual minimum fees from fee-based margin to non-fee-based margin in order to conform to the current period classification.
 Years Ended December 31,  
 2019 2018 Change
Gathering and processing fee-based revenues$2,002
 $1,788
 $214
Non-fee based contracts and processing452
 589
 (137)
Total segment margin$2,454
 $2,377
 $77
Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following:
a decrease of $137 million in non fee-based margin due to lower NGL prices of $131 million and lower gas prices of $58 million, offset by an increase of $52 million in non fee-based margin due to increased throughput volume in North Texas, South Texas and Permian regions;
an increase of $86 million in operating expenses due to increases of $33 million in outside services, $29 million in maintenance project costs, $17 million in employee costs and $6 million in office expenses and materials; and
an increase of $9 million in selling, general and administrative expenses primarily due to a decrease of $5 million in capitalized overhead and an increase of $4 million in insurance expense; partially offset by
an increase of $214 million in fee-based margin due to volume growth in the Northeast, Permian, Ark-La-Tex, North Texas and South Texas regions.


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NGL and Refined Products Transportation and Services
 Years Ended December 31,  
 2019 2018 Change
NGL transportation volumes (MBbls/d)1,289
 1,027
 262
Refined products transportation volumes (MBbls/d)583
 621
 (38)
NGL and refined products terminal volumes (MBbls/d)944
 812
 132
NGL fractionation volumes (MBbls/d)706
 527
 179
Revenues$11,641
 $11,123
 $518
Cost of products sold8,393
 8,462
 (69)
Segment margin3,248
 2,661
 587
Unrealized (gains) losses on commodity risk management activities81
 (86) 167
Operating expenses, excluding non-cash compensation expense(656) (604) (52)
Selling, general and administrative expenses, excluding non-cash compensation expense(93) (74) (19)
Adjusted EBITDA related to unconsolidated affiliates86
 82
 4
Segment Adjusted EBITDA$2,666
 $1,979
 $687
Volumes. For the year ended December 31, 2019 compared to the prior year, throughput barrels on our Texas NGL pipeline system increased due to higher receipt of liquids production from both wholly-owned and third-party gas plants primarily in the Permian and North Texas regions. In addition, NGL transportation volumes on our Northeast assets increased due to the initiation of service on the Mariner East 2 pipeline system.
Refined products transportation volumes decreased for the year ended December 31, 2019 compared to prior year due to the closure of a third party refinery during the third quarter of 2019, negatively impacting supply to our refined products transportation system. These decreases in volumes are partially offset by the initiation of service on the JC Nolan Pipeline in the third quarter of 2019.
NGL and refined products terminal volumes increased for the year ended December 31, 2019 compared to the prior year primarily due to the initiation of service on our Mariner East 2 pipeline system which commenced operations in the fourth quarter of 2018.
Average volumes fractionated at our Mont Belvieu, Texas fractionation facility increased for the year ended December 31, 2019 compared to the prior year primarily due to the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively.
Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:
 Years Ended December 31,  
 2019 2018 Change
Fractionators and refinery services margin$664
 $511
 $153
Transportation margin1,716
 1,233
 483
Storage margin223
 211
 12
Terminal Services margin630
 494
 136
Marketing margin96
 126
 (30)
Unrealized gains (losses) on commodity risk management activities(81) 86
 (167)
Total segment margin$3,248
 $2,661
 $587
Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
an increase of $483 million in transportation margin primarily due to a $265 million increase resulting from the initiation of service on our Mariner East 2 pipeline in the fourth quarter of 2018, a $212 million increase resulting from higher throughput volumes received from the Permian region on our Texas NGL pipelines, a $29 million increase due to higher throughput volumes from the Barnett region, a $9 million increase from the Eagle Ford region, and a $9 million increase due to the

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initiation of service on the JC Nolan Pipeline. These increases were partially offset by a $21 million decrease resulting from Mariner East 1 pipeline downtime, a $13 million decrease due to the closure of a third-party refinery during the third quarter of 2019, negatively impacting refined product supply to our system, and a $5 million decrease due to the timing of deficiency fees on Mariner West;
an increase of $153 million in fractionation and refinery services margin primarily due to a $167 million increase resulting from the commissioning of our fifth and sixth fractionators in July 2018 and February 2019, respectively, and higher NGL volumes from the Permian region feeding our Mont Belvieu fractionation facility. This increase was partially offset by a reclassification between our fractionation and storage margins;
an increase of $136 million in terminal services margin primarily due to a $171 million increase from the initiation of service of our Mariner East 2 pipeline which commenced operations in the fourth quarter of 2018 and a $7 million increase due to increased tank lease revenue from third-party customers. These increases were partially offset by a $16 million decrease in volumes and expense reimbursements from third parties on Mariner East 1, a $16 million decrease due to lower volumes from third party pipeline, truck and rail deliveries into our Marcus Hook terminal, a $5 million decrease due to fewer vessels exported out of our Nederland terminal, and a $4 million decrease due to the closure of a third party refinery during the third quarter of 2019; and
an increase of $12 million in storage margin primarily due to a reclassification between our storage and fractionation margins; partially offset by
a decrease of $30 million in marketing margin primarily due to capacity lease fees incurred by our marketing affiliate on our Mariner East 2 pipeline, offset by increased gains from our butane blending business due to more favorable market conditions and increased volumes, as well as increased optimization gains from the sale of NGL component products at our Mont Belvieu facility;
an increase of $52 million in operating expenses primarily due to a $26 million increase in employee and ad valorem tax expenses on our terminals, fractionation, and transportation operations, a $14 million increase in utility costs to operate our pipelines and our fifth and sixth fractionators which commenced July 2018 and February 2019, respectively, and an $8 million increase in maintenance project costs due to the timing of multiple projects on our transportation assets; and
an increase of $19 million in general and administrative expenses primarily due to a $10 million increase in allocated overhead costs, a $5 million increase in insurance expenses, a $4 million increase in legal fees, and a $2 million increase in employee costs.
Crude Oil Transportation and Services
 Years Ended December 31,  
 2019 2018 Change
Crude transportation volumes (MBbls/d)4,662
 4,172
 490
Crude terminals volumes (MBbls/d)2,068
 2,096
 (28)
Revenue$18,447
 $17,332
 $1,115
Cost of products sold14,758
 14,439
 319
Segment margin3,689
 2,893
 796
Unrealized (gains) losses on commodity risk management activities(69) 55
 (124)
Operating expenses, excluding non-cash compensation expense(570) (547) (23)
Selling, general and administrative expenses, excluding non-cash compensation expense(85) (86) 1
Adjusted EBITDA related to unconsolidated affiliates8
 15
 (7)
Other(1) 
 (1)
Segment Adjusted EBITDA$2,972
 $2,330
 $642
Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
an increase of $672 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a $282 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from the Permian region and contributions from capacity expansion projects placed into service, a $219 million increase in throughput on our Bakken pipeline, a favorable inventory valuation adjustment of

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$111 million for the 2019 year as compared to an unfavorable inventory adjustment of $54 million for the 2018 year, partially offset by a $50 million reduction due to lower pipeline basis spreads net of hedges. We also realized a $66 million increase from higher volumes on our Bayou Bridge Pipeline, a $31 million increase due to the inclusion of assets acquired in 2019, and a $26 million increase primarily from higher throughput, ship loading and tank rental fees at our Nederland terminal; partially offset by a $54 million decrease from our Oklahoma assets resulting from lower volumes to the system as well as from the timing of a deficiency payment made in the prior year, $12 million decrease due to the closure of a third party refinery which was the primary customer utilizing one of our northeast crude terminals. The remainder of the offsetting decrease was primarily attributable to a change in the presentation of certain intrasegment transactions, which were eliminated in the current period presentation but were shown on a gross basis in revenues and operating expenses in the prior period; partially offset by
an increase of $23 million in operating expenses primarily due to a $30 million increase in throughput-related costs on existing assets and a $10 million increase due to the inclusion of expenses acquired in 2019, partially offset by a $14 million decrease in management fees as well as the impact of certain intrasegment transactions discussed above;
a decrease of $7 million in Adjusted EBITDA related to unconsolidated affiliates due to lower margin from jet fuel sales by our joint ventures.
Investment in Sunoco LP
 Years Ended December 31,  
 2019 2018 Change
Revenues$16,596
 $16,994
 $(398)
Cost of products sold15,380
 15,872
 (492)
Segment margin1,216
 1,122
 94
Unrealized (gains) losses on commodity risk management activities(5) 6
 (11)
Operating expenses, excluding non-cash compensation expense(365) (435) 70
Selling, general and administrative, excluding non-cash compensation expense(123) (129) 6
Adjusted EBITDA related to unconsolidated affiliates4
 
 4
Inventory valuation adjustments(79) 85
 (164)
Adjusted EBITDA from discontinued operations
 (25) 25
Other, net17
 14
 3
Segment Adjusted EBITDA$665
 $638
 $27
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment increased due to the net impacts of the following:
a decrease in operating costs of $76 million, primarily as a result of the conversion of 207 retail sites to commission agent sites during April 2018. These expenses include other operating expense, general and administrative expense and lease expense; and
an increase of $25 million related to Adjusted EBITDA from discontinued operations related to the divestment of 1,030 company-operated fuel sites to 7-Eleven in January 2018; and
an increase of $4 million in Adjusted EBITDA related to unconsolidated affiliates due to Sunoco LP’s investment in the JC Nolan joint venture; partially offset by
a decrease in the gross profit on motor fuel sales of $76 million (excluding the change in inventory fair value adjustments and unrealized gains and losses on commodity risk management activities) primarily due to lower fuel margins, a one-time benefit of approximately $25 million related to a cash settlement with a fuel supplier recorded in 2018 and an $8 million one-time charge related to a reserve for an open contractual dispute recorded in 2019, partially offset by an increase in gallons sold.



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Investment in USAC
 Years Ended December 31,  
 2019 2018 Change
Revenues$698
 $508
 $190
Cost of products sold91
 67
 24
Segment margin607
 441
 166
Operating expenses, excluding non-cash compensation expense(134) (110) (24)
Selling, general and administrative, excluding non-cash compensation expense(53) (50) (3)
Other, net
 8
 (8)
Segment Adjusted EBITDA$420
 $289
 $131
Amounts reflected above for the year ended December 31, 2019 represents the results of operations for USAC from April 2, 2018, the date ET obtained control of USAC, through December 31, 2019. Changes between periods are due to the consolidation of USAC beginning April 2, 2018.
All Other
 Years Ended December 31,  
 2019 2018 Change
Revenue$1,689
 $2,228
 $(539)
Cost of products sold1,504
 2,006
 (502)
Segment margin185
 222
 (37)
Unrealized gains on commodity risk management activities(4) (2) (2)
Operating expenses, excluding non-cash compensation expense(77) (56) (21)
Selling, general and administrative expenses, excluding non-cash compensation expense(66) (124) 58
Adjusted EBITDA related to unconsolidated affiliates2
 1
 1
Other and eliminations58
 (1) 59
Segment Adjusted EBITDA$98
 $40
 $58
Amounts reflected in our all other segment primarily include:
our natural gas marketing operations;
our wholly-owned natural gas compression operations;
a non-controlling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent the August 2018 reorganization, ETO holds an approximately 7.4% interest in PES and no longer reflects PES as an affiliate;
our investment in coal handling facilities; and
our Canadian operations, which were acquired in the SemGroup acquisition in December 2019 and include natural gas gathering and processing assets.
Segment Adjusted EBITDA. For the year ended December 31, 2019 compared to the prior year, Segment Adjusted EBITDA increased due to the net impact of the following:
an increase of $8 million in gains from park and loan and storage activity;
an increase of $11 million in optimized gains on residue gas sales;
an increase of $7 million from settled derivatives;
an increase of $15 million from a legal settlement;

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an increase of $12 million from payments related to the PES bankruptcy;
an increase of $6 million from the recognition of deferred revenue related to a bankruptcy;
an increase of $3 million from power trading activities;
an increase of $3 million from the SemCAMS joint venture for the period subsequent to our acquisition of SemGroup on December 5, 2019, net of an increase in SemGroup corporate expenses; and
a decrease of $40 million in merger and acquisition expenses; partially offset by
a decrease of $36 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;
a decrease of $8 million due to lower gas prices and increased power costs; and
a decrease of $11 million due to lower revenue from our compressor equipment business.
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Consolidated Results
 Years Ended December 31,  
 2018 2017 Change
Segment Adjusted EBITDA:     
Intrastate transportation and storage$927
 $626
 $301
Interstate transportation and storage1,680
 1,274
 406
Midstream1,627
 1,481
 146
NGL and refined products transportation and services1,979
 1,641
 338
Crude oil transportation and services2,330
 1,379
 951
Investment in Sunoco LP638
 732
 (94)
Investment in USAC289
 
 289
All other40
 187
 (147)
Total9,510
 7,320
 2,190
Depreciation, depletion and amortization(2,859) (2,554) (305)
Interest expense, net of interest capitalized(2,055) (1,922) (133)
Impairment losses(431) (1,039) 608
Gains (losses) on interest rate derivatives47
 (37) 84
Non-cash compensation expense(105) (99) (6)
Unrealized gains (losses) on commodity risk management activities(11) 59
 (70)
Inventory valuation adjustments(85) 24
 (109)
Losses on extinguishments of debt(112) (89) (23)
Adjusted EBITDA related to unconsolidated affiliates(655) (716) 61
Equity in earnings of unconsolidated affiliates344
 144
 200
Impairment of investments in unconsolidated affiliates
 (313) 313
Adjusted EBITDA related to discontinued operations25
 (223) 248
Other, net21
 155
 (134)
Income from continuing operations before income tax (expense) benefit3,634
 710
 2,924
Income tax (expense) benefit from continuing operations(4) 1,833
 (1,837)
Income from continuing operations3,630
 2,543
 1,087
Loss from discontinued operations, net of income taxes(265) (177) (88)
Net income$3,365
 $2,366
 $999
Adjusted EBITDA (consolidated). For the year ended December 31, 2018 compared to the prior year, Adjusted EBITDA increased approximately $2.2 billion, or 30%. The increase was primarily due to the impact of multiple revenue-generating assets being

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placed in service and recent acquisitions, as well as increased demand for services on existing assets. The impact of new assets and acquisitions was approximately $1.2 billion, of which the largest increases were from the Bakken pipeline (a $546 million impact to the crude oil transportation and services segment), the Rover pipeline (a $359 million impact to the interstate transportation and storage segment) and the acquisition of USAC (a net impact of $191 million among the investment in USAC and all other segments). The remainder of the increase in Adjusted EBITDA was primarily due to stronger demand on existing assets, particularly due to increased production in the Permian, which impacted multiple segments. Additional discussion of these and other factors affecting Adjusted EBITDA is included in the analysis 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, net of interest capitalized, increased primarily due to the following:
an increase of $121 million recognized by ETO primarily related to an increase in long-term debt, including additional senior note issuances and borrowings under our revolving credit facilities; and
an increase of $78 million due to the acquisition of USAC on April 2, 2018; partially offset by
a decrease of $65 million recognized by Sunoco LP primarily due to the repayment in full of its term loan and refinancing of its senior notes at lower rates.
Impairment Losses. During the year ended December 31, 2018, the Partnership recognized goodwill impairments of $378 million and asset impairments of $4 million related to our midstream operations and asset impairments of $9 million related to our crude operations idle leased assets. Sunoco LP recognized a $30 million indefinite-lived intangible impairment related to its contractual rights. USAC recognized a $9 million fixed asset impairment related to certain idle compressor assets.
During the year ended December 31, 2017, the Partnership recorded goodwill impairments of $223 million related to the compression business, $229 million related to Panhandle, $262 million related to the interstate transportation and storage segment and $79 million related to the NGL and refined products transportation and services segment. Sunoco LP recognized goodwill impairments of $387 million in 2017, of which $102 million was allocated to continuing operations. In addition, during the year ended December 31, 2017, the Partnership recorded an impairment to the property, plant and equipment of Sea Robin of $127 million. Additional discussion on these impairments is included in “Estimates and Critical Accounting Policies” below.
Gains (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. Gains (losses) on interest rate derivatives during the years ended December 31, 2018 and 2017 resulted from an increase in forward interest rates in 2018 and a decrease in forward interest rates in 2017, which caused our forward-starting swaps to change 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 as a result of commodity price changes in between periods.
Losses on Extinguishments of Debt. Amounts were related to Sunoco LP’s senior note and term loan redemption in January 2018.
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.
Impairment of Investments in Unconsolidated Affiliates. During the year ended December 31, 2017, the Partnership recorded impairments to its investments in FEP of $141 million and HPC of $172 million. Additional discussion on these impairments is included in “Estimates and Critical Accounting Policies” below.
Adjusted EBITDA Related to Discontinued Operations. Amounts were related to the operations of Sunoco LP’s retail business that were disposed of in January 2018.
Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.
Income Tax (Expense) 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

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2018, the Partnership recorded an income tax expense due to pre-tax income at its corporate subsidiaries, partially offset by a statutory rate reduction.
Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
 Years Ended December 31,  
 2018 2017 Change
Equity in earnings (losses) of unconsolidated affiliates:     
Citrus$141
 $144
 $(3)
FEP55
 53
 2
MEP31
 38
 (7)
HPC (1)(2)
3
 (168) 171
Other114
 77
 37
Total equity in earnings of unconsolidated affiliates$344
 $144
 $200
      
Adjusted EBITDA related to unconsolidated affiliates(3):
     
Citrus$337
 $336
 $1
FEP74
 74
 
MEP81
 88
 (7)
HPC (2)
9
 46
 (37)
Other154
 172
 (18)
Total Adjusted EBITDA related to unconsolidated affiliates$655
 $716
 $(61)
      
Distributions received from unconsolidated affiliates:     
Citrus$171
 $156
 $15
FEP68
 47
 21
MEP48
 114
 (66)
HPC (2)

 35
 (35)
Other110
 80
 30
Total distributions received from unconsolidated affiliates$397
 $432
 $(35)
(1) 
The partnership previously owned a 49.99% interest in HPC, which owns RIGS. In April 2018, we acquired the remaining 50.01% interest in HPC. Prior to April 2018, HPC was reflected as an unconsolidated affiliate in our financial statements; beginning in April 2018, RIGS is reflected as a wholly-owned subsidiary in our financial statements.
(2) 
For the year ended December 31, 2017, equity in earnings of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million.
(3) 
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion, amortization, non-cash items and taxes.

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Segment Operating Results
Intrastate Transportation and Storage
 Years Ended December 31,  
 2018 2017 Change
Natural gas transported (BBtu/d)10,873
 8,427
 2,446
Revenues$3,737
 $3,083
 $654
Cost of products sold2,665
 2,327
 338
Segment margin1,072
 756
 316
Unrealized (gains) losses on commodity risk management activities38
 (5) 43
Operating expenses, excluding non-cash compensation expense(189) (168) (21)
Selling, general and administrative, excluding non-cash compensation expense(27) (22) (5)
Adjusted EBITDA related to unconsolidated affiliates32
 64
 (32)
Other1
 1
 
Segment Adjusted EBITDA$927
 $626
 $301
Volumes.  For the year ended December 31, 2018 compared to the prior year, transported volumes increased primarily due to favorable market pricing spreads, as well as the impact of reflecting RIGS assets as a consolidated subsidiary beginning in April 2018.
Segment Margin.  The components of our intrastate transportation and storage segment margin were as follows:
 Years Ended December 31,  
 2018 2017 Change
Transportation fees$525
 $448
 $77
Natural gas sales and other (excluding unrealized gains and losses)510
 196
 314
Retained fuel revenues (excluding unrealized gains and losses)59
 58
 1
Storage margin, including fees (excluding unrealized gains and losses)16
 49
 (33)
Unrealized gains (losses) on commodity risk management activities(38) 5
 (43)
Total segment margin$1,072
 $756
 $316
Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our intrastate transportation and storage segment increased due to the net impacts of the following:
an increase of $314 million in realized natural gas sales and other due to higher realized gains from pipeline optimization activity;
a net increase of $14 million due to the consolidation of RIGS beginning in April 2018, resulting in increases in transportation fees, operating expenses, and selling, general and administrative expenses of $73 million, $16 million and $6 million, respectively, and a decrease of $37 million in Adjusted EBITDA related to unconsolidated affiliates; and
an increase of $4 million in transportation fees, excluding the impact of consolidating RIGS as discussed above, primarily due to new contracts and the impact of the Red Bluff Express pipeline coming online in May 2018; partially offset by
a decrease of $33 million in realized storage margin primarily due to an adjustment to the Bammel storage inventory, lower storage fees and lower realized derivative gains.

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Interstate Transportation and Storage
 Years Ended December 31,  
 2018 2017 Change
Natural gas transported (BBtu/d)9,542
 6,058
 3,484
Natural gas sold (BBtu/d)17
 18
 (1)
Revenues$1,682
 $1,131
 $551
Operating expenses, excluding non-cash compensation, amortization and accretion expenses(431) (315) (116)
Selling, general and administrative, excluding non-cash compensation, amortization and accretion expenses(63) (41) (22)
Adjusted EBITDA related to unconsolidated affiliates492
 498
 (6)
Other
 1
 (1)
Segment Adjusted EBITDA$1,680
 $1,274
 $406
Volumes. For the year ended December 31, 2018 compared to the prior year, transported volumes reflected increases of 1,919 BBtu/d as a result of the initiation of service on the Rover pipeline; increases of 572 BBtu/d and 439 BBtu/d on the Panhandle and Trunkline pipelines, respectively, due to higher demand resulting from colder weather and increased utilization by the Rover pipeline; 375 BBtu/d on the Tiger pipeline as a result of production increases in the Haynesville Shale, and 145 BBtu/d on the Transwestern pipeline resulting from favorable market opportunities in the West, midcontinent and Waha areas from the Permian supply basin.
Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following:
an increase of $359 million associated with the Rover pipeline with increases of $485 million in revenues, $105 million in net operating expenses and $21 million in selling, general and administrative expenses and other; and
an aggregate increase of $66 million in revenues, excluding the incremental revenue related to the Rover pipeline discussed above, primarily due to capacity sold at higher rates on the Transwestern and Panhandle pipelines; partially offset by
an increase of $11 million in operating expenses, excluding the incremental expenses related to the Rover pipeline discussed above, primarily due to increases in maintenance project costs due to scope and level of activity; and
a decrease of $6 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to lower margins on MEP due to lower rates on renewals of expiring long term contracts.
Midstream
 Years Ended December 31,  
 2018 2017 Change
Gathered volumes (BBtu/d):12,126
 9,814
 2,312
NGLs produced (MBbls/d):540
 438
 102
Equity NGLs (MBbls/d):29
 31
 (2)
Revenues$7,522
 $6,943
 $579
Cost of products sold5,145
 4,761
 384
Segment margin2,377
 2,182
 195
Unrealized gains on commodity risk management activities
 (15) 15
Operating expenses, excluding non-cash compensation expense(705) (638) (67)
Selling, general and administrative, excluding non-cash compensation expense(81) (78) (3)
Adjusted EBITDA related to unconsolidated affiliates33
 28
 5
Other3
 2
 1
Segment Adjusted EBITDA$1,627
 $1,481
 $146

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Volumes. Gathered volumes and NGL production increased during the year ended December 31, 2018 compared to the prior year primarily due to increases in the North Texas, Permian and Northeast regions, partially offset by smaller declines in other regions.
Segment Margin.  The table below presents the components of our midstream segment margin. For the years ended December 31, 2018 and 2017, the amounts previously reported for fee-based and non-fee-based margin have been adjusted to reflect reclassification of certain contractual minimum fees from fee-based margin to non-fee-based margin in order to conform to the current period classification.
 Years Ended December 31,  
 2018 2017 Change
Gathering and processing fee-based revenues$1,788
 $1,690
 $98
Non-fee based contracts and processing (excluding unrealized gains and losses)589
 477
 112
Unrealized gains on commodity risk management activities
 15
 (15)
Total segment margin$2,377
 $2,182
 $195
Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following:
an increase of $98 million in fee-based margin due to growth in the North Texas, Permian and Northeast regions, offset by declines in the Ark-La-Tex and midcontinent/Panhandle regions;
an increase of $79 million in non fee-based margin due to increased throughput volume in the North Texas and Permian regions;
an increase of $33 million in non fee-based margin due to higher crude oil and NGL prices; and
an increase of $5 million in Adjusted EBITDA related to unconsolidated affiliates due to higher earnings from our Aqua, Mi Vida and Ranch joint ventures; partially offset by
an increase of $67 million in operating expenses primarily due to increases of $20 million in outside services, $19 million in materials, $8 million in maintenance project costs, $7 million in ad valorem taxes, $6 million in employee costs and $6 million in office expenses; and
an increase of $3 million in selling, general and administrative expenses due to higher professional fees.
NGL and Refined Products Transportation and Services
 Years Ended December 31,  
 2018 2017 Change
NGL transportation volumes (MBbls/d)1,027
 754
 273
Refined products transportation volumes (MBbls/d)621
 599
 22
NGL and refined products terminal volumes (MBbls/d)812
 791
 21
NGL fractionation volumes (MBbls/d)527
 361
 166
Revenues$11,123
 $8,648
 $2,475
Cost of products sold8,462
 6,508
 1,954
Segment margin2,661
 2,140
 521
Unrealized gains on commodity risk management activities(86) (26) (60)
Operating expenses, excluding non-cash compensation expense(604) (478) (126)
Selling, general and administrative expenses, excluding non-cash compensation expense(74) (64) (10)
Adjusted EBITDA related to unconsolidated affiliates82
 68
 14
Other
 1
 (1)
Segment Adjusted EBITDA$1,979
 $1,641
 $338

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Volumes. For the year ended December 31, 2018 compared to the prior year, NGL transportation volumes increased primarily due to increased volumes from the Permian region resulting from a ramp up in production from existing customers, higher throughput volumes on Mariner West driven by end-user facility constraints in the prior year and higher throughput from Mariner South resulting from increased export volumes.
Refined products transportation volumes decreased for the year ended December 31, 2018 compared to prior year, primarily due to timing of turnarounds at third-party refineries in the Midwest and Northeast regions.
NGL and Refined products terminal volumes increased for the year ended December 31, 2018 compared to prior year, primarily due to more volumes loaded at our Nederland terminal as propane export demand increased and higher throughput volumes at our refined products terminals in the Northeast.
Average volumes fractionated at our Mont Belvieu, Texas fractionation facility increased for the year ended December 31, 2018 compared to the prior year primarily due to increased volumes from the Permian region, as well as an increase in fractionation capacity as our fifth fractionator at Mont Belvieu came online in July 2018.
Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:
 Years Ended December 31,  
 2018 2017 Change
Fractionators and refinery services margin$511
 $415
 $96
Transportation margin1,233
 990
 243
Storage margin211
 214
 (3)
Terminal Services margin494
 424
 70
Marketing margin126
 71
 55
Unrealized gains on commodity risk management activities86
 26
 60
Total segment margin$2,661
 $2,140
 $521
Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment increased due to the net impacts of the following:
an increase in transportation margin of $243 million primarily due to a $216 million increase resulting from increased producer volumes from the Permian region on our Texas NGL pipelines, a $31 million increase due to higher throughput volumes on Mariner West driven by end-user facility constraints in the prior period, a $15 million increase resulting from a reclassification between our transportation and fractionation margins, a $9 million increase due to higher throughput volumes from the Barnett region, a $5 million increase due to higher throughput volumes on Mariner South due to system downtime in the prior period and a $4 million increase in prior period customer credits. These increases were partially offset by a $16 million decrease resulting from lower throughput volumes on Mariner East 1 due to system downtime in 2018, a $14 million decrease due to lower throughput volumes from the Southeast Texas region and a $7 million decrease resulting from the timing of deficiency fee revenue recognition;
an increase in fractionation and refinery services margin of $96 million primarily due to a $106 million increase resulting from the commissioning of our fifth fractionator in July 2018 and a $7 million increase from blending gains as a result of improved market pricing. These increases were partially offset by a $16 million decrease resulting from a reclassification between our transportation and fractionation margins and a $2 million decrease from higher affiliate storage fees paid;
an increase in terminal services margin of $70 million due to a $36 million increase resulting from a change in the classification of certain customer reimbursements previously recorded in operating expenses, a $23 million increase at our Nederland terminal due to increased export demand and a $12 million increase due to higher throughput at our Marcus Hook Industrial Complex. These increases were partially offset by lower terminal throughput fees in part due to the sale of one of our terminals in April 2017;
an increase in marketing margin of $55 million due to a $48 million increase from our butane blending operations and a $22 million increase in sales of NGLs and other products at our Marcus Hook Industrial Complex due to more favorable market prices. These increases were partially offset by a $15 million decrease from the timing of optimization gains from our Mont Belvieu fractionators; and
an increase of $14 million to adjusted EBITDA related to unconsolidated affiliates due to improved contributions from our unconsolidated refined products joint venture interests; partially offset by

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an increase of $126 million in operating expenses primarily due to a $30 million increase in costs to operate our fractionators and a $20 million increase in operating costs on our NGL pipelines as a result of higher throughput and the commissioning of our fifth fractionator in July 2018, a $36 million increase resulting from a change in the classification of certain customer reimbursements previously recorded as a reduction to operating expenses that are now classified as revenue following the adoption of ASC 606 on January 1, 2018, increases of $24 million and $7 million to operating costs at our Marcus Hook and Nederland terminals, respectively, as a result of significantly higher volumes through both terminals in 2018, an $8 million increase to environmental reserves and a $1 million increase to overhead allocations and maintenance repairs performed on our refinery services assets; and
an increase of $10 million in selling, general and administrative expenses primarily due to a $6 million increase in overhead costs allocated to the segment, a $2 million increase in legal fees, a $1 million increase in management fees previously recorded in operating expenses and a $1 million increase in employee costs.
Crude Oil Transportation and Services
 Years Ended December 31,  
 2018 2017 Change
Crude Transportation Volumes (MBbls/d)4,172
 3,538
 634
Crude Terminals Volumes (MBbls/d)2,096
 1,928
 168
Revenue$17,332
 $11,703
 $5,629
Cost of products sold14,439
 9,826
 4,613
Segment margin2,893
 1,877
 1,016
Unrealized losses on commodity risk management activities55
 1
 54
Operating expenses, excluding non-cash compensation expense(547) (430) (117)
Selling, general and administrative expenses, excluding non-cash compensation expense(86) (82) (4)
Adjusted EBITDA related to unconsolidated affiliates15
 13
 2
Segment Adjusted EBITDA$2,330
 $1,379
 $951
Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to our crude oil transportation and services segment increased due to the net impacts of the following:
an increase of $1.07 billion in segment margin (excluding unrealized losses on commodity risk management activities) primarily due to the following: a $586 million increase resulting from placing the Bakken pipeline in service in the second quarter of 2017, a $266 million increase resulting from higher throughput on our Texas crude pipeline system primarily due to increased production from Permian producers; and gains of $355 million due to more favorable basis spreads; partially offset by an unfavorable inventory valuation adjustment of $54 million for the 2018 year as compared to a favorable inventory valuation adjustment of $82 million for the 2017 year; and
an increase of $2 million in Adjusted EBITDA related to unconsolidated affiliates due to increased jet fuel sales from our joint ventures; partially offset by
an increase of $117 million in operating expenses primarily due to a $67 million increase to throughput related costs on existing assets; a $36 million increase resulting from placing the Bakken pipeline in service in the second quarter of 2017; a $26 million increase resulting from the addition of certain joint venture transportation assets in the second quarter of 2017; and a $5 million increase from ad valorem taxes; partially offset by an $17 million decrease in insurance and environmental related expenses; and
an increase of $4 million in selling, general and administrative expenses primarily due to increases associated with placing our Bakken Pipeline in service in the second quarter of 2017.

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Investment in Sunoco LP
 Years Ended December 31,  
 2018 2017 Change
Revenues$16,994
 $11,723
 $5,271
Cost of products sold15,872
 10,615
 5,257
Segment margin1,122
 1,108
 14
Unrealized (gains) losses on commodity risk management activities6
 (3) 9
Operating expenses, excluding non-cash compensation expense(435) (456) 21
Selling, general and administrative, excluding non-cash compensation expense(129) (116) (13)
Inventory valuation adjustments85
 (24) 109
Adjusted EBITDA from discontinued operations(25) 223
 (248)
Other, net14
 
 14
Segment Adjusted EBITDA$638
 $732
 $(94)
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA related to the Investment in Sunoco LP segment decreased due to the net impacts of the following:
a decrease of $248 million in Adjusted EBITDA from discontinued operations primarily due to Sunoco LP’s retail divestment in January 2018; partially offset by
an increase of $109 million in inventory fair value adjustments due to changes in fuel prices between periods;
an increase of $14 million in margin primarily due to an increase in rental income as a result of the increase in commission agent sites in the current year, offset by decreases in the gross profit on motor fuel sales; and
a net decrease of $8 million in operating and selling, general and administrative expenses primarily due to decreased rent expense.
Investment in USAC
 Years Ended December 31,  
 2018 2017 Change
Revenues$508
 $
 $508
Cost of products sold67
 
 67
Segment margin441
 
 441
Operating expenses, excluding non-cash compensation expense(110) 
 (110)
Selling, general and administrative, excluding non-cash compensation expense(50) 
 (50)
Other, net8
 
 8
Segment Adjusted EBITDA$289
 $
 $289
The investment in USAC segment reflects the consolidated results of USAC from April 2, 2018, the date ET obtained control of USAC, through December 31, 2018. Changes between periods are due to the consolidation of USAC beginning April 2, 2018.

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All Other
 Years Ended December 31,  
 2018 2017 Change
Revenue$2,228
 $2,901
 $(673)
Cost of products sold2,006
 2,509
 (503)
Segment margin222
 392
 (170)
Unrealized gains on commodity risk management activities(2) (11) 9
Operating expenses, excluding non-cash compensation expense(56) (117) 61
Selling, general and administrative expenses, excluding non-cash compensation expense(124) (135) 11
Adjusted EBITDA related to unconsolidated affiliates1
 45
 (44)
Other and eliminations(1) 13
 (14)
Segment Adjusted EBITDA$40
 $187
 $(147)
Amounts reflected in our all other segment during the periods presented above primarily include:
our natural gas marketing operations;
our wholly-owned natural gas compression operations;
a non-controlling interest in PES. Prior to PES’s reorganization in August 2018, ETO’s 33% interest in PES was reflected as an unconsolidated affiliate; subsequent the August 2018 reorganization, ETO holds an approximately 8% interest in PES and no longer reflects PES as an affiliate; and
our investment in coal handling facilities.
Segment Adjusted EBITDA. For the year ended December 31, 2018 compared to the prior year, Segment Adjusted EBITDA decreased due to the net impacts of the following:
a decrease of $98 million due to the contribution of CDM to USAC in April 2018, subsequent to which CDM is reflected in the Investment in USAC segment;
a decrease of $38 million in Adjusted EBITDA related to unconsolidated affiliates from our investment in PES primarily due to our lower ownership in PES subsequent to its reorganization, which resulted in PES no longer being reflected as an affiliate beginning in the third quarter of 2018;
a decrease of $4 million due to merger and acquisition expenses related to the Energy Transfer Merger in 2018; and
a decrease of $15 million due to a one-time fee received from a joint venture affiliate in 2017; partially offset by
an increase of $7 million due to lower transport fees resulting from the expiration of a capacity commitment on Trunkline pipeline;
an increase of $6 million due to a decrease in losses from mark-to-market of physical system gas; and
an increase of $7 million due to increased margin from ETO’s compression equipment business.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Parent Company Only
Subsequent to the Merger with ETO, substantially all of the Partnership’s cash flows are derived from distributions related to its investment in ETO, whose cash flows are derived from its subsidiaries, including ETO’s investments in Sunoco LP and USAC.
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 ETO. The Parent Company distributes its available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.

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The Parent Company expects ETO and its respective subsidiaries and investments in Sunoco LP and USAC 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 it deems prudent to provide liquidity for new capital projects of its subsidiaries or for other partnership purposes.
ETO
ETO’s ability to satisfy its obligations and pay distributions to the Parent Company 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 ETO’s management.
ETO currently expects capital expenditures in 2020 to be within the following ranges (excluding capital expenditures related to our investments in Sunoco LP and USAC):
 Growth Maintenance
 Low High Low High
Intrastate transportation and storage$20
 $30
 $40
 $45
Interstate transportation and storage (1)
100
 125
 140
 145
Midstream625
 650
 125
 130
NGL and refined products transportation and services (1)
2,550
 2,650
 100
 110
Crude oil transportation and services (1)
500
 525
 165
 175
All other (including eliminations)125
 150
 75
 80
Total capital expenditures$3,920
 $4,130
 $645
 $685
(1) 
Includes capital expenditures related to ETO’s proportionate ownership of the Bakken, Rover, and Bayou Bridge pipeline projects and our proportionate ownership of the Orbit Gulf Coast NGL export project.
The assets used in our 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, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience 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 timely, higher steel prices and other factors beyond our control. However, we include these factors in our anticipated growth capital expenditures for each year.
ETO generally funds maintenance capital expenditures and distributions with cash flows from operating activities. ETO generally expects to funds growth capital expenditures with proceeds of borrowings under ETO credit facilities, along with cash from operations.
As of December 31, 2019, in addition to $253 million of cash on hand, ETO had available capacity under the ETO Credit Facilities of $1.71 billion. Based on ETO’s current estimates, ETO expects to utilize capacity under the ETO Credit Facilities, along with cash from operations, to fund ETO’s announced growth capital expenditures and working capital needs through the end of 2020; however, ETO may issue debt or equity securities prior to that time as ETO deems prudent to provide liquidity for new capital projects, to maintain investment grade credit metrics or other partnership purposes.
Sunoco LP
Sunoco LP’s primary sources of liquidity consist of cash generated from operating activities, borrowings under its $1.50 billion credit facility and the issuance of additional long-term debt or partnership units as appropriate given market conditions. At December 31, 2019, Sunoco LP had available borrowing capacity of $1.33 billion under its revolving credit facility and $21 million of cash and cash equivalents on hand.
In 2020, Sunoco LP expects to invest approximately $130 million in growth capital expenditures and approximately $45 million on maintenance capital expenditures. Sunoco LP may revise the timing of these expenditures as necessary to adapt to economic conditions.

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USAC
The compression services business is capital intensive, requiring significant investment to maintain, expand and upgrade existing operations. USAC’s capital requirements have consisted primarily of, and it anticipates that its capital requirements will continue to consist primarily of, the following:
maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of its assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining its existing business and related operating income; and
expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that were not currently generating operating income.
USAC classifies capital expenditures as maintenance or expansion on an individual asset basis. Over the long-term, USAC expects that its maintenance capital expenditure requirements will continue to increase as the overall size and age of its fleet increase. USAC currently plans to spend approximately $32 million in maintenance capital expenditures during 2020, including parts consumed from inventory.
Without giving effect to any equipment USAC may acquire pursuant to any future acquisitions, it currently has budgeted between $110 million and $120 million in expansion capital expenditures during 2020. As of December 31, 2019, USAC has binding commitments to purchase $49 million of additional compression units, all of which USAC expects to be delivered in 2020.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price of our 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 acquisitions of assets, while changes in non-cash 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 ETO 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 derivative 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, 2019
Cash provided by operating activities in 2019 was $8.00 billion and income from continuing operations was $4.90 billion. The difference between net income and cash provided by operating activities in 2019 primarily consisted of non-cash items totaling $3.37 billion offset by net changes in operating assets and liabilities of $518 million. The non-cash activity in 2019 consisted primarily of depreciation, depletion and amortization of $3.15 billion, impairment losses of $74 million, non-cash compensation expense of $113 million, equity in earnings of unconsolidated affiliates of $302 million, inventory valuation adjustments of $79 million, losses on extinguishment of debt of $18 million, and deferred income tax expense of $217 million. The Partnership also received distributions of $290 million from unconsolidated affiliates.
Year Ended December 31, 2018
Cash provided by operating activities in 2018 was $7.51 billion and income from continuing operations was $3.63 billion. The difference between net income and cash provided by operating activities in 2018 primarily consisted of non-cash items totaling $3.30 billion offset by net changes in operating assets and liabilities of $289 million. The non-cash activity in 2018 consisted primarily of depreciation, depletion and amortization of $2.86 billion, impairment losses of $431 million, non-cash compensation expense of $105 million, equity in earnings of unconsolidated affiliates of $344 million, inventory valuation adjustments of

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$85 million, losses on extinguishment of debt of $112 million, and deferred income tax benefit of $7 million. The Partnership also received distributions of $328 million from unconsolidated affiliates.
Year Ended December 31, 2017
Cash provided by operating activities in 2017 was $4.43 billion and income from continuing operations was $2.54 billion. The difference between net income and cash provided by operating activities in 2017 primarily consisted of non-cash items totaling $1.82 billion offset by net changes in operating assets and liabilities of $192 million. The non-cash activity in 2017 consisted primarily of depreciation, depletion and amortization of $2.55 billion, impairment losses of $1.04 billion, impairment in unconsolidated affiliates of $313 million, non-cash compensation expense of $99 million, equity in earnings of unconsolidated affiliates of $144 million, inventory valuation adjustments of $24 million, losses on extinguishment of debt of $89 million, and deferred income tax benefit of $1.87 billion. The Partnership also received distributions of $297 million from unconsolidated affiliates.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures, and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects.
Following is a summary of investing activities by period:
Year Ended December 31, 2019
Cash used in investing activities in 2019 was $6.93 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $5.88 billion. Additional detail related to our capital expenditures is provided in the table below. During 2019, we received $93 million of cash proceeds from the sale of a noncontrolling interest in a subsidiary, paid $787 million in net cash for the SemGroup acquisition, and paid $7 million in cash for all other acquisitions. We received $54 million of cash proceeds from the sale of assets. The Partnership also received distributions of $98 million from unconsolidated affiliates.
Year Ended December 31, 2018
Cash used in investing activities in 2018 was $7.08 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $7.30 billion. Additional detail related to our capital expenditures is provided in the table below. We recorded a net increase in cash of $461 million related to the USAC acquisition and paid $429 million in cash for all other acquisitions. We received $87 million of cash proceeds from the sale of assets. The Partnership also received distributions of $69 million from unconsolidated affiliates.
Year Ended December 31, 2017
Cash used in investing activities in 2017 was $5.61 billion. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) were $8.41 billion. Additional detail related to our capital expenditures is provided in the table below. We paid $280 million in cash related to the acquisition of PennTex’s remaining noncontrolling interest and $303 million in cash for all other acquisitions. We received $2.00 billion in cash related to the Bakken equity sale to MarEn Bakken Company LLC, $1.48 billion in cash related to the Rover equity sale to Blackstone Capital Partners. We received $48 million of cash proceeds from the sale of assets. The Partnership also received distributions of $135 million from unconsolidated affiliates.

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The following is a summary of the Partnership’s capital expenditures (including only our proportionate share of the Bakken, Rover, and Bayou Bridge pipeline projects, our proportionate share of the Orbit Gulf Coast NGL export project, and net of contributions in aid of construction costs) by period:
 Capital Expenditures Recorded During Period
Growth Maintenance Total
Year Ended December 31, 2019:     
Intrastate transportation and storage$87
 $37
 $124
Interstate transportation and storage239
 136
 375
Midstream670
 157
 827
NGL and refined products transportation and services2,854
 122
 2,976
Crude oil transportation and services317
 86
 403
Investment in Sunoco LP108
 40
 148
Investment in USAC170
 30
 200
All other (including eliminations)165
 50
 215
Total capital expenditures$4,610
 $658
 $5,268
      
Year Ended December 31, 2018:     
Intrastate transportation and storage$311
 $33
 $344
Interstate transportation and storage695
 117
 812
Midstream1,026
 135
 1,161
NGL and refined products transportation and services2,303
 78
 2,381
Crude oil transportation and services414
 60
 474
Investment in Sunoco LP (1)
72
 31
 103
Investment in USAC182
 23
 205
All other (including eliminations)117
 33
 150
Total capital expenditures$5,120
 $510
 $5,630
      
Year Ended December 31, 2017:     
Intrastate transportation and storage$155
 $20
 $175
Interstate transportation and storage645
 83
 728
Midstream1,185
 123
 1,308
NGL and refined products transportation and services2,899
 72
 2,971
Crude oil transportation and services392
 61
 453
Investment in Sunoco LP (1)
129
 48
 177
All other (including eliminations)196
 72
 268
Total capital expenditures$5,601
 $479
 $6,080
(1) 
Amounts related to Sunoco LP’s capital expenditures include capital expenditures related to discontinued operations.
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 our acquisitions and growth capital expenditures. Distributions to partners increased between the periods as a result of increases in the number of common units outstanding or increases in the distribution rate.

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Following is a summary of financing activities by period:
Year Ended December 31, 2019
Cash used in financing activities was $1.20 billion in 2019. In 2019, our subsidiaries received $780 million in proceeds from the issuance of preferred units. In 2019, we had a consolidated increase in our debt level of $2.48 billion, primarily due to the issuance of subsidiary senior notes. During 2019, we paid distributions of $3.05 billion to our partners and we paid distributions of $1.60 billion to noncontrolling interests. In addition, we received capital contributions of $348 million in cash from noncontrolling interests. During 2019, we incurred debt issuance costs of $117 million.
Year Ended December 31, 2018
Cash used in financing activities was $3.08 billion in 2018. Our subsidiaries received $1.40 billion in proceeds from the issuance of common units, including $58 million from the issuance of ETO Common Units and $1.34 billion from the issuance of other subsidiary common units. In 2018, we had a consolidated increase in our debt level of $53 million, primarily due to the issuance of Parent Company and subsidiary senior notes. During 2018, we paid distributions of $1.68 billion to our partners and we paid distributions of $3.12 billion to noncontrolling interests. In addition, we received capital contributions of $649 million in cash from noncontrolling interests. During 2018, we incurred debt issuance costs of $171 million.
Year Ended December 31, 2017
Cash provided by financing activities was $953 million in 2017. In 2017, we received $568 million in cash from the issuance of common units and our subsidiaries received $3.24 billion in proceeds from the issuance of common units, including $2.28 billion from the issuance of ETO Common Units and $952 million from the issuance of other subsidiary common units. In 2017, we had a consolidated increase in our debt level of $340 million, primarily due to the issuance of Parent Company and subsidiary senior notes. During 2017, we paid distributions of $1.01 billion to our partners and we paid distributions of $2.96 billion to noncontrolling interests. In addition, we received capital contributions of $1.21 billion in cash from noncontrolling interests. During 2017, we incurred debt issuance costs of $131 million.
Discontinued Operations
Following is a summary of activities related to discontinued operations by period:
Year Ended December 31, 2018
Cash provided by discontinued operations was $2.73 billion for the year ended December 31, 2018 resulting from cash used in operating activities of $484 million, cash provided by investing activities of $3.21 billion, and changes in cash included in current assets held for sale of $11 million.
Year Ended December 31, 2017
Cash provided by discontinued operations was $93 million for the year ended December 31, 2017 resulting from cash provided by operating activities of $136 million, cash used in investing activities of $38 million and changes in cash included in current assets held for sale of $5 million.

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Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
 December 31,
 2019 2018
Parent Company Indebtedness:   
ET Senior Notes due October 2020$52
 $1,187
ET Senior Notes due March 20235
 1,000
ET Senior Notes due January 202423
 1,150
ET Senior Notes due June 202744
 1,000
ET Senior Secured Term Loan
 1,220
Subsidiary Indebtedness:   
ETO Senior Notes36,118
 28,755
Transwestern Senior Notes575
 575
Panhandle Senior Notes235
 385
Bakken Senior Notes2,500
 
Sunoco LP Senior Notes, Term Loan and lease-related obligations2,935
 2,307
USAC Senior Notes1,475
 725
Credit Facilities and Commercial Paper:   
ETO $2.00 billion Term Loan facility due October 20222,000
 
ETO $5.00 billion Revolving Credit Facility due December 20234,214
 3,694
Sunoco LP $1.50 billion Revolving Credit Facility due July 2023162
 700
USAC $1.60 billion Revolving Credit Facility due April 2023403
 1,050
Bakken $2.50 billion Credit Facility due August 2019
 2,500
HFOTCO Tax Exempt Notes due 2050225
 
SemCAMS Revolver due February 202492
 
SemCAMS Term Loan A due February 2024269
 
Other long-term debt2
 7
Unamortized premiums, net of discounts and fair value adjustments4
 21
Deferred debt issuance costs(279) (248)
Total debt51,054
 46,028
Less: current maturities of long-term debt26
 2,655
Long-term debt, less current maturities$51,028
 $43,373
The terms of our consolidated indebtedness and that of our subsidiaries are described in more detail below and in Note 6 to our consolidated financial statements, included in “Item 8. Financial Statements and Supplementary Data.”
Recent Transactions
ETO January 2020 Senior Notes Offering and Redemption
On January 22, 2020, ETO completed a registered offering (the “January 2020 Senior Notes Offering”) of $1.00 billion aggregate principal amount of ETO’s 2.900% Senior Notes due 2025, $1.50 billion aggregate principal amount of ETO’s 3.750% Senior Notes due 2030, and $2.00 billion aggregate principal amount of ETO’s 5.000% Senior Notes due 2050, (collectively, the “Notes”). The Notes are fully and unconditionally guaranteed by the Partnership’s wholly-owned subsidiary, Sunoco Logistics Partners Operations L.P., on a senior unsecured basis.
Utilizing proceeds from the January 2020 Senior Notes Offering, ETO redeemed its $400 million aggregate principal amount of 5.75% Senior Notes due September 1, 2020, its $1.05 billion aggregate principal amount of 4.15% Senior Notes due October 1, 2020, its $1.14 billion aggregate principal amount of 7.50% Senior Notes due October 15, 2020, its $250 million aggregate principal

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amount of 5.50% Senior Notes due February 15, 2020, ET’s $52 million aggregate principal amount of 7.50% Senior Notes due October 15, 2020 and Transwestern’s $175 million aggregate principal amount of 5.36% Senior Notes due December 9, 2020.
ETO Term Loan
On October 17, 2019, ETO entered into a term loan credit agreement (the “ETO Term Loan”) providing for a $2.00 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P.
ET-ETO Senior Notes Exchange
In February 2019, ETO commenced offers to exchange all of ET’s outstanding senior notes for senior notes issued by ETO (the “ET-ETO senior notes exchange”).  Approximately 97% of ET’s outstanding senior notes were tendered and accepted, and substantially all the exchanges settled on March 25, 2019. In connection with the exchange, ETO issued approximately $4.21 billion aggregate principal amount of the following senior notes:
$1.14 billion aggregate principal amount of 7.50% senior notes due 2020;
$995 million aggregate principal amount of 4.25% senior notes due 2023;
$1.13 billion aggregate principal amount of 5.875% senior notes due 2024; and
$956 million aggregate principal amount of 5.50% senior notes due 2027.
ETO 2019 Senior Notes Offering and Redemption
In January 2019, ETO issued the following senior notes:
$750 million aggregate principal amount of 4.50% senior notes due 2024;
$1.50 billion aggregate principal amount of 5.25% senior notes due 2029; and
$1.75 billion aggregate principal amount of 6.25% senior notes due 2049.
The $3.96 billion net proceeds from the offering were used to make an intercompany loan to ET (which ET used to repay its term loan in full), for general partnership purposes and to redeem at maturity all of the following:
ETO’s $400 million aggregate principal amount of 9.70% senior notes due March 15, 2019;
ETO’s $450 million aggregate principal amount of 9.00% senior notes due April 15, 2019; and
Panhandle’s $150 million aggregate principal amount of 8.125% senior notes due June 1, 2019.
Panhandle Senior Notes Redemption
In June 2019, Panhandle’s $150 million aggregate principal amount of 8.125% senior notes matured and were repaid with borrowings under an affiliate loan agreement with ETO.
Bakken Senior Notes Offering
In March 2019, Midwest Connector Capital Company LLC, a wholly-owned subsidiary of Dakota Access, issued the following senior notes related to the Bakken pipeline:
$650 million aggregate principal amount of 3.625% senior notes due 2022;
$1.00 billion aggregate principal amount of 3.90% senior notes due 2024; and
$850 million aggregate principal amount of 4.625% senior notes due 2029.
The $2.48 billion in net proceeds from the offering were used to repay in full all amounts outstanding on the Bakken credit facility and the facility was terminated.
Sunoco LP Senior Notes Offering
In March 2019, Sunoco LP issued $600 million aggregate principal amount of 6.00% senior notes due 2027 in a private placement to eligible purchasers. The net proceeds from this offering were used to repay a portion of Sunoco LP’s existing borrowings under its credit facility. In July 2019, Sunoco LP completed an exchange of these notes for registered notes with substantially identical terms.

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USAC Senior Notes Offering
In March 2019, USAC issued $750 million aggregate principal amount of 6.875% senior notes due 2027 in a private placement, and in December 2019, USAC exchanged those notes for substantially identical senior notes registered under the Securities Act. The net proceeds from this offering were used to repay a portion of USAC’s existing borrowings under its credit facility and for general partnership purposes.
Credit Facilities and Commercial Paper
Parent Company Credit Facility
In connection with the closing of the Energy Transfer Merger, on October 19, 2018, the Partnership repaid in full all outstanding borrowings under the facility and the facility was terminated.
ETO Credit Facilities
Borrowings under the ETO Credit Facilities are unsecured and initially guaranteed by Sunoco Logistics Partners Operations L.P.  Borrowings under the ETO Credit Facilities will bear interest at a eurodollar rate or a base rate, at our option, plus an applicable margin.  In addition, we 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 ETO Credit Facilities. 
We typically repay amounts outstanding under the ETO Credit Facilities with proceeds from unit offerings or long-term notes offerings. The timing of borrowings depends on the Partnership’s activities and the cash available to fund those activities. The repayments of amounts outstanding under the ETO Credit Facilities 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 ETO Credit Facilities may vary significantly between periods. We do not believe that such fluctuations indicate a significant change in our liquidity position, because we expect to continue to be able to repay amounts outstanding under the ETO Credit Facilities with proceeds from unit offerings or long-term note offerings.
ETO Term Loan
On October 17, 2019, ETO entered into a term loan credit agreement (the “ETO Term Loan”) providing for a $2.00 billion three-year term loan credit facility. Borrowings under the term loan agreement mature on October 17, 2022 and are available for working capital purposes and for general partnership purposes. The term loan agreement is unsecured and is guaranteed by our subsidiary, Sunoco Logistics Partners Operations L.P.
As of December 31, 2019, the ETO Term Loan had $2.00 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2019 was 2.78%.
ETO Five-Year Credit Facility
ETO’s revolving credit facility (the “ETO Five-Year Credit Facility”) allows for unsecured borrowings up to $5.00 billion and matures on December 1, 2023. The ETO Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $6.00 billion under certain conditions.
As of December 31, 2019, the ETO Five-Year Credit Facility had $4.21 billion outstanding, of which $1.64 billion was commercial paper. The amount available for future borrowings was $709 million after taking into account letters of credit of $77 million. The weighted average interest rate on the total amount outstanding as of December 31, 2019 was 2.88%.
ETO 364-Day Facility
ETO’s 364-day revolving credit facility (the “ETO 364-Day Facility”) allows for unsecured borrowings up to $1.00 billion and matures on November 27, 2020. As of December 31, 2019, the ETO 364-Day Facility had no outstanding borrowings.
Sunoco LP Credit Facility
As of December 31, 2019, the Sunoco LP Credit Facility had $162 million outstanding borrowings and $8 million in standby letters of credit. The amount available for future borrowings was at December 31, 2019 was $1.33 billion. The weighted average interest rate on the total amount outstanding as of December 31, 2019 was 3.75%.

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USAC Credit Facility
As of December 31, 2019, USAC had $403 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of December 31, 2019, USAC had $1.20 billion of availability under its credit facility. The weighted average interest rate on the total amount outstanding as of December 31, 2019 was 4.31%.
SemCAMS Credit Facilities
SemCAMS is party to a credit agreement providing for a C$350 million (US$270 million at the December 31, 2019 exchange rate) senior secured term loan facility, a C$$525 million (US$404 million at the December 31, 2019 exchange rate) senior secured revolving credit facility, and a C$300 million (US$231 million at the December 31, 2019 exchange rate) senior secured construction loan facility (the “KAPS Facility”). The term loan facility and the revolving credit facility mature on February 25, 2024. The KAPS Facility matures on June 13, 2024. SemCAMS may incur additional term loans and revolving commitments in an aggregate amount not to exceed C$250 million (US$193 million at the December 31, 2019 exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders.
Covenants Related to Our Credit Agreements
Covenants Related to the Parent Company
The Term Loan Facility and ET Revolving Credit Facility previously contained 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. Both facilities have been paid off and terminated.
Covenants Related to ETO
The agreements relating to the ETO 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 ETO Credit Facilities contain 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 ETO Credit Facilities) during certain Defaults (as defined in the ETO Credit Facilities) and during any Event of Default (as defined in the ETO 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 ETO 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 ETO 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 ETO Five-Year Facility ranges from 0.125% to 0.300%.  The applicable margin for eurodollar rate loans under the ETO 364-Day Facility ranges from 1.250% 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 ETO 364-Day Facility ranges from 0.125% to 0.225%.
The ETO 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 ETO 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 4.04 to 1 at December 31, 2019, as calculated in accordance with the credit agreements.

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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 Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions to Unitholders.
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.
Panhandle’s restrictive covenants include restrictions on liens securing debt and guarantees and restrictions on mergers and on the sales of assets. A breach of any of these covenants could result in acceleration of Panhandle’s debt.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a Net Leverage Ratio of not more than 5.5 to 1. The maximum Net Leverage Ratio is subject to upwards adjustment of not more than 6.0 to 1 for a period not to exceed three fiscal quarters in the event Sunoco LP engages in certain specified acquisitions of not less than $50 million (as permitted under Sunoco LP’s Credit Facility agreement). The Sunoco LP Credit Facility also requires Sunoco LP to maintain an Interest Coverage Ratio (as defined in the Sunoco LP’s Credit Facility agreement) of not less than 2.25 to 1.
Covenants Related to USAC
The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things: 
grant liens;
make certain loans or investments;
incur additional indebtedness or guarantee other indebtedness;
merge or consolidate;
sell our assets; or
make certain acquisitions.
The credit facility is also subject to the following financial covenants, including covenants requiring us to maintain:
a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and
a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (i) 5.5 to 1 through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0 to 1.0 thereafter, in each case subject to a provision for increases to such thresholds by 0.50 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.
Covenants Related to the HFOTCO Tax Exempt Notes
The indentures covering HFOTCO's tax exempt notes due 2050 ("IKE Bonds") include customary representations and warranties and affirmative and negative covenants. Such covenants include limitations on the creation of new liens, indebtedness, making of certain restricted payments and payments on indebtedness, making certain dispositions, making material changes in business activities, making fundamental changes including liquidations, mergers or consolidations, making certain investments, entering into certain transactions with affiliates, making amendments to certain credit or organizational agreements, modifying the fiscal year, creating or dealing with hazardous materials in certain ways, entering into certain hedging arrangements, entering into certain restrictive agreements, funding or engaging in sanctioned activities, taking actions or causing the trustee to take actions that materially adversely affect the rights, interests, remedies or security of the bondholders, taking actions to remove the trustee, making certain amendments to the bond documents, and taking actions or omitting to take actions that adversely impact the tax exempt status of the IKE Bonds.

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Compliance with our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2019.
Contractual Obligations
The following table summarizes our long-term debt and other contractual obligations as of December 31, 2019:
  Payments Due by Period
Contractual Obligations Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years
Long-term debt $51,329
 $3,086
 $7,204
 $13,673
 $27,366
Interest on long-term debt(1)
 41,196
 2,545
 4,958
 4,306
 29,387
Payments on derivatives 401
 150
 251
 
 
Purchase commitments(2)
 2,133
 2,053
 57
 7
 16
Transportation, natural gas storage and fractionation contracts 16
 5
 6
 5
 
Operating lease obligations 1,548
 98
 166
 140
 1,144
Service concession arrangement(3)
 379
 15
 30
 32
 302
Other(4)
 190
 25
 48
 40
 77
Total(5)
 $97,192
 $7,977
 $12,720
 $18,203
 $58,292
(1) 
Interest payments on long-term debt are based on the principal amount of debt obligations as of December 31, 2019. With respect to variable rate debt, the interest payments were estimated using the interest rate as of December 31, 2019. To the extent interest rates change, our contractual obligations 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, 2019 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.
(3) 
Includes minimum guaranteed payments under service concession arrangements with New Jersey Turnpike Authority and New York Thruway Authority.
(4) 
Expected contributions to fund our pension and postretirement benefit plans were included in “Other” above. Environmental liabilities, AROs, 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 the amounts do not represent contractual obligations or, in some cases, the amount and/or timing of the cash payments is uncertain.
(5) 
Excludes net non-current deferred tax liabilities of $3.21 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 are as follows:
Quarter Ended            Record Date  Payment Date  Rate
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
March 31, 2018 May 7, 2018 May 21, 2018 0.3050
June 30, 2018 August 6, 2018 August 20, 2018 0.3050
September 30, 2018 November 8, 2018 November 19, 2018 0.3050
December 31, 2018 February 8, 2019 February 19, 2019 0.3050
March 31, 2019 May 7, 2019 May 20, 2019 0.3050
June 30, 2019 August 6, 2019 August 19, 2019 0.3050
September 30, 2019 November 5, 2019 November 19, 2019 0.3050
December 31, 2019 February 7, 2020 February 19, 2020 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 ET Series A Convertible Preferred 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 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 ET Series A Convertible Preferred Unit were as follows:
Quarter Ended          Record Date Payment Date  Rate
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
March 31, 2018 May 7, 2018 May 21, 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,
 2019 
2018 (1)
 2017
Limited Partners$3,221
 $2,215
 $1,022
General Partner interest4
 3
 3
Total Parent Company distributions$3,225
 $2,218
 $1,025
(1)  
Include distributions declared by Energy Transfer LP for periods subsequent to the Energy Transfer Merger.

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The total amounts of distributions declared and paid during the periods presented prior to the closing of the Energy Transfer Merger as discussed in Note 1 (all from Available Cash from ETO’s operating surplus and are shown in the period to which they relate) are as follows:
 Years Ended December 31,
 2018 2017
Common Units held by public$1,286
 $2,435
Common Units held by ET31
 61
General Partner interest and IDRs900
 1,654
IDR relinquishments (1)
(84) (656)
Series A Preferred Units59
 15
Series B Preferred Units36
 9
Series C Preferred Units (2)
23
 
Series D Preferred Units (2)
15
 
Total distributions declared to partners$2,266
 $3,518
(1) 
Net of Class I unit distributions
(2) 
Distributions reflect prorated distributions for the year ended December 31, 2018.
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.
ETO Preferred Unit Distributions
Distributions on the ETO’s Series A, Series B, Series C, Series D and Series E preferred units declared and/or paid by ETO were as follows:
Period Ended Record Date Payment Date 
Series A (1)
 
Series B (1)
 Series C Series D Series E 
December 31, 2017 February 1, 2018 February 15, 2018 $15.4510
* 
$16.3780
* 
$
 $
 $
 
June 30, 2018 August 1, 2018 August 15, 2018 31.2500
 33.1250
 0.5634
* 

 
 
September 30, 2018 November 1, 2018 November 15, 2018 
 
 0.4609
 0.5931
* 

 
December 31, 2018 February 1, 2019 February 15, 2019 31.2500
 33.1250
 0.4609
 0.4766
 
 
March 31, 2019 May 1, 2019 May 15, 2019 
 
 0.4609
 0.4766
 
 
June 30, 2019 August 1, 2019 August 15, 2019 31.2500
 33.1250
 0.4609
 0.4766
 0.5806
* 
September 30, 2019 November 1, 2019 November 15, 2019 
 
 0.4609
 0.4766
 0.4750
 
December 31, 2019 February 3, 2020 February 18, 2020 31.2500
 33.1250
 0.4609
 0.4766
 0.4750
 
* 
Represent prorated initial distributions. Prorated initial distributions on the recently issued ETO Series F Preferred Units and ETO Series G Preferred Units will be payable in May 2020.   
(1)    ETO Series A Preferred Units and ETO Series B Preferred Unit distributions are paid on a semi-annual basis.   

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Sunoco LP Cash Distributions
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.
    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 on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:
Quarter Ended Record Date Payment Date Rate
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 6, 2018 February 14, 2018 0.8255
March 31, 2018 May 7, 2018 May 15, 2018 0.8255
June 30, 2018 August 7, 2018 August 15, 2018 0.8255
September 30, 2018 November 6, 2018 November 14, 2018 0.8255
December 31, 2018 February 6, 2019 February 14, 2019 0.8255
March 31, 2019 May 7, 2019 May 15, 2019 0.8255
June 30, 2019 August 6, 2019 August 14, 2019 0.8255
September 30, 2019 November 5, 2019 November 19, 2019 0.8255
December 31, 2019 February 7, 2020 February 19, 2020 0.8255
The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows:
 Years Ended December 31,
 2019 2018 2017
Distributions from Sunoco LP     
Limited Partner interests$94
 $94
 $150
General Partner interest and IDRs70
 70
 85
Series A Preferred
 2
 23
Total distributions from Sunoco LP$164
 $166
 $258
USAC Cash Distributions
Subsequent to the Energy Transfer Merger and USAC Transactions described in Note 1 and Note 3, respectively, ETO owned approximately 39.7 million USAC common units and 6.4 million USAC Class B units. Subsequent to the conversion of the USAC

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Class B Units to USAC common units on July 30, 2019, ETO owns approximately 46.1 million USAC common units. As of December 31, 2019, USAC had approximately 96.6 million common units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.
Distributions on USAC’s units declared and/or paid by USAC subsequent to the USAC transaction on April 2, 2018 were as follows:
Quarter Ended Record Date Payment Date Rate
March 31, 2018 May 1, 2018 May 11, 2018 $0.5250
June 30, 2018 July 30, 2018 August 10, 2018 0.5250
September 30, 2018 October 29, 2018 November 09, 2018 0.5250
December 31, 2018 January 28, 2019 February 8, 2019 0.5250
March 31, 2019 April 29, 2019 May 10, 2019 0.5250
June 30, 2019 July 29, 2019 August 9, 2019 0.5250
September 30, 2019 October 28, 2019 November 8, 2019 0.5250
December 31, 2019 January 27, 2020 February 7, 2020 0.5250
The total amount of distributions to the Partnership from USAC for the periods presented below is as follows:
 Years Ended December 31,
 2019 2018 2017
Distributions from USAC     
Limited Partner interests$90
 $73
 $
Total distributions from USAC$90
 $73
 $
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 the midstream, NGL and intrastate transportation and storage segments 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, 2019 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.
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

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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. Excess fuel retained after consumption 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.
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.
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. Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates and some third-party customers.
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, and (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. 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.
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.
We have a risk management policy that provides for oversight over our marketing activities. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. As a result of our 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. We attempt 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 our risk management policy.
We inject and hold 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. We use financial derivatives to hedge the natural gas held in connection with these arbitrage opportunities. At the inception of the hedge, we lock in a margin by purchasing gas in the spot market or off peak

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season and entering 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 the hedged natural gas inventory at current spot 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 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, we will record unrealized gains or lower unrealized losses. If the spread widens, we will record unrealized losses or lower unrealized gains. Typically, as we enter the winter months, the spread converges so that we recognize in earnings the original locked in spread, either through mark-to-market or the physical withdrawal of natural gas.
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.
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.
Investment in Sunoco LP
Sunoco LP’s revenues from motor fuel 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 wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Through PropCo, Sunoco LP’s wholly-owned corporate subsidiary, Sunoco LP may sell motor fuel to customers on a commission agent basis, in which Sunoco LP retains title to inventory, controls access to and sale of fuel inventory, and recognizes revenue at the time the fuel is sold to the ultimate customer. In Sunoco LP’s fuel distribution and marketing operations, Sunoco LP derives other income from rental income, propane and lubricating oils, and other ancillary product and service offerings. In Sunoco LP’s other operations, Sunoco LP derives other income from merchandise, lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals, and other ancillary product and service offerings. Sunoco LP records revenue from other retail transactions on a net commission basis when a product is sold and/or services are rendered.
Investment in USAC
USAC’s revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under its fixed-fee contracts over the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years. However, USAC usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay its monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue.  The amount of consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.
USAC’s retail parts and services revenue is earned primarily on freight and crane charges that are directly reimbursable by its customers and maintenance work on units at its customers’ locations that are outside the scope of USAC’s core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration USAC receives and revenue it recognizes is based upon the invoice amount.  

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Lease Accounting.  At the inception of each lease arrangement, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of 12 months or less on the balance sheet.
Balances related to operating leases are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make minimum lease payments arising from the lease for the duration of the lease term.
Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of lease renewal options is typically at the sole discretion of the Partnership and lease extensions are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. The depreciable life of lease assets and leasehold improvements are limited by the expected lease term.
To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease payments made and exclude lease incentives.
Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically responsible for include payment of real estate taxes, maintenance expenses and insurance.
For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and no ROU assets are recorded.
Accounting for Derivative Instruments and Hedging Activities.  We utilize various exchange-traded and OTC commodity financial instrument contracts to limit our exposure to margin fluctuations in natural gas, NGL, crude oil and refined products. These contracts consist primarily of futures and swaps.
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.
If we designate a 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 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.
We utilize 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 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

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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 to the embedded derivatives in our 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. 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 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