We were formed in September 2002 and completed our initial public offering in February 2006. We are a Delaware limited partnership with common units publicly traded on the NYSE under the ticker symbol “ETE.”

In January 2014 and July 2015, the Partnership completed two-for-one splits of its outstanding common units. All references to units and per unit amounts in this document have been adjusted to reflect the effect of the unit splits for all periods presented.

The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and the Partnership’s ownership of Lake Charles LNG.

At December 31, 2016,January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 2.627.5 million ETP common units, and approximately 81.02.3 million ETP Class HSunoco LP common units. We also own 0.1% of Sunoco Partners LLC, the entity that owns the general partner interest and IDRs of Sunoco Logistics, while ETP owns the remaining 99.9% of Sunoco Partners LLC. Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously providedare currently not entitled to ETP.any distributions.

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 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.

Our significant strategic transactions in 20162017 and beyond included the following, as discussed in more detail herein:

Our primary business objective is to increase cash available for distributions to our unitholders by actively assisting our subsidiaries in executing their business strategies by assisting in identifying, evaluating and pursuing strategic acquisitions and growth opportunities. In general, we expect that we will allow our subsidiaries the first opportunity to pursue any acquisition or internal growth project that may be presented to us which may be within the scope of their operations or business strategies. In the future, we may also support the growth of our subsidiaries through the use of our capital resources, which could involve loans, capital contributions or other forms of credit support to our subsidiaries. This funding could be used for the acquisition by one of our subsidiaries of a business or asset or for an internal growth project. In addition, the availability of this capital could assist our subsidiaries in arranging financing for a project, reducing its financing costs or otherwise supporting a merger or acquisition transaction.

Our reportable segments are as follows:

ETP’s operations include the following:

ETP’s natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems and deliver the natural gas to industrial end-users, storage facilities, utilities and other pipelines. Through its intrastate transportation and storage operations, ETP owns and operates approximately 7,900 miles of natural gas transportation pipelines with approximately 15.2 Bcf/d of transportation capacity and three natural gas storage facilities located in the state of

Through ETC OLP, ETP owns the largest intrastate pipeline system in the United States with interconnects to Texas markets and to major consumption areas throughout the United States. ETP’s intrastate transportation and storage operations focus on the transportation of natural gas to major markets from various prolific natural gas producing areas through connections with other pipeline systems as well as through its Oasis pipeline, its East Texas pipeline, its natural gas pipeline and storage assets that are referred to as the ET Fuel System, and its HPL System, which are described below.

ETP’s intrastate transportation and storage operations results are determined primarily by the amount of capacity its customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly.

ETP also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and marketing companies on the HPL System. In addition, ETP’s intrastate transportation and storage operations generate revenues from fees charged for storing customers’ working natural gas in ETP’s storage facilities and from managing natural gas for its own account.

ETP’s interstate transportation and storage operations include Panhandle, which owns and operates a large natural gas open-access interstate pipeline network.  The pipeline network, consisting of the Panhandle, Trunkline and Sea Robin transmission systems, serves customers in the Midwest, Gulf Coast and Midcontinent United States with a comprehensive array of transportation and storage services.  In connection with its natural gas pipeline transmission and storage systems, Panhandle has five natural gas storage fields located in Illinois, Kansas, Louisiana, Michigan and Oklahoma.  Southwest Gas operates four of these fields and Trunkline operates one.

ETP also owns a 50% interest in the MEP pipeline system, which is operated by KMI, and has the capability to transport up to 1.8 Bcf/d of natural gas.

Gulf States is a small interstate pipeline that uses cost-based rates and terms and conditions of service for shippers wishing to secure capacity for interstate transportation service. Rates charged are largely governed by long-term negotiated rate agreements.

The results from ETP’s interstate transportation and storage operations are primarily derived from the fees ETP earns from natural gas transportation and storage services.

The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. The midstream industry consists of natural gas gathering, compression, treating, processing, storage and transportation, and is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells and the proximity of storage facilities to production areas and end-use markets.

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

Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and to continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise might not be produced.

Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is higher in carbon dioxide, hydrogen sulfide or certain other contaminants. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications.

Some natural gas produced by a well does not meet the pipeline quality specifications established by downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable margins for NGLs extracted from the gas stream. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream.

Through its midstream operations, ETP owns and operates natural gas and NGL gathering pipelines, natural gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing, treating and conditioning capacity

of approximately 12.3 Bcf/d. ETP’s midstream operations focus on the gathering, compression, treating, blending, and processing, of natural gas and its operations are currently concentrated in major producing basins and shales, including the Austin Chalk trend and Eagle Ford Shale in South and Southeast Texas, the Permian Basin in West Texas and New Mexico, the Barnett Shale and Woodford Shale in North Texas, the Bossier Sands in East Texas, the Marcellus Shale in West Virginia and Pennsylvania, and the Haynesville Shale in East Texas and Louisiana. Many of ETP’s midstream assets are integrated with ourits intrastate transportation and storage assets.

OurETP’s midstream operations also include a 60% interest in ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in South Texas, a 33.33% membership interest in Ranch Westex JV LLC, which processes natural gas delivered from the NGLs-rich shale formations in West Texas, a 75% membership interest in ORS, which operates a natural gas gathering system in the Utica shale in Ohio, and a 50% interest in Mi Vida JV, which operates a cryogenic processing plant and related facilities in West Texas, a 51% membership interest in Aqua – PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania, and a 50% interest in Sweeny Gathering LP, which operates a natural gas gathering facility in South Texas.

The results from ETP’s midstream operations are primarily derived from margins ETP earns for natural gas volumes that are gathered, transported, purchased and sold through ETP’s pipeline systems and the natural gas and NGL volumes processed at its processing and treating facilities.

NGLLiquids transportation pipelines transport mixed NGLs and other hydrocarbons from natural gas processing facilities to fractionation plants and storage facilities. NGL storage facilities are used for the storage of mixed NGLs, NGL products and petrochemical products owned by third parties in storage tanks and underground wells, which allow for the injection and withdrawal of such products at various times of the year to meet demand cycles. NGL fractionators separate mixed NGL streams into purity products, such as ethane, propane, normal butane, isobutane and natural gasoline.

ETP’s liquidsNGL and refined products transportation and services operations includesinclude approximately 1,4004,300 miles of NGL pipelines, with an aggregate transportation capacity in excess of 1.5 million Bbls/d, five NGL and propane fractionation facilities with an aggregate capacity of 545,000 Bbls/545 MBbls/d and NGL storage facilities with aggregate working storage capacity of approximately 53 million Bbls. Four of ETP’s NGL and propane fractionation facilities and 50 million Bbls of ETP’s NGL storage capacity are located at Mont Belvieu, Texas, one NGL fractionation facility is located in Geismar, Louisiana, and operations havethe segment has 3 million Bbls of salt dome storage capacity near Hattiesburg, Mississippi. ETP is currently constructing a fifth and sixth fractionator in Mont Belvieu, Texas, which are expected to be operational in the third quarter of 2018 and the second quarter of 2019, respectively. The NGL pipelines primarily transport NGLs from the Permian and Delaware basins and the Barnett and Eagle Ford Shales to Mont Belvieu. In addition, ETP owns

Terminalling services are facilitated by approximately 7 million Bbls of NGLs storage capacity, including approximately 1 million Bbls of storage at ETP’s Nederland, Texas terminal facility, 1 million Bbls of storage at our Inkster, Michigan terminal facility and operates5 million Bbls at ETP’s Marcus Hook, Pennsylvania terminal facility (the “Marcus Hook Industrial Complex”). These operations also support ETP’s NGLs blending activities, including the 82-mile Rio Bravo crude oil pipeline.use of ETP’s patented butane blending technology.

Liquids transportation revenue is principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Transportation fees are market-based, negotiated with customers and competitive with regional regulated pipelines.

NGL fractionation revenue is principally generated from fees charged to customers under take-or-pay contracts. Take-or-pay contracts have minimum payment obligations for throughput commitments requiring the customer to pay regardless of whether a fixed volume is fractionated from raw make into purity NGL products. Fractionation fees are market-based, negotiated with customers and competitive with other fractionators along the Gulf Coast.

NGL storage revenues are derived from base storage fees and throughput fees. Base storage fees are firm take or pay contracts on the volume of capacity reserved, regardless of the capacity actually used. Throughput fees are charged for providing ancillary services, including receipt and delivery and custody transfer fees.

These operationsThis segment also includes revenues earned from the marketing of NGLs and processing and fractionating refinery off-gas. Marketing of NGLs primarily generates margin from selling ratable NGLs to end users and from optimizing storage assets.

Processing and fractionation of refinery off-gas margin is generated from a percentage-of-proceeds of O-grade product sales and income sharing contracts, which are subject to market pricing of olefins and NGLs.

ETP’s Investment in Sunoco Logistics

ETP’s crude oil operations provide transportation, terminalling and acquisition and marketing services to crude oil markets throughout the southwest, midwest and northeastern United States. Included within thesethe operations are approximately 6,1009,360 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States and equity ownership interests in two crude oil pipelines. Sunoco Logistics’ETP’s crude oil terminalling services operate with an aggregate storage capacity of approximately 33 million barrels,Bbls, including approximately 26 million barrelsBbls at itsETP’s Gulf Coast terminal in Nederland, Texas and approximately 3 million barrelsBbls at itsETP’s Fort Mifflin terminal complex in Pennsylvania. Sunoco Logistics’ETP’s crude oil acquisition and marketing activities utilize its pipeline and terminal assets, its proprietary fleet crude oil tractor trailers and truck unloading facilities, as well as third-party assets, to service crude oil markets principally in the mid-continent United States.

Sunoco Logistics’ NGLs operations transport, store,Revenues throughout ETP’s crude oil pipeline systems are generated from tariffs paid by shippers utilizing its transportation services. These tariffs are filed with the FERC and executeother state regulatory agencies, as applicable.

ETP’s crude oil acquisition and marketing activities utilizing a complementary networkinclude the gathering, purchasing, marketing and selling of pipelines, storage and blending facilities, and strategic off-take locations that provide access to multiple NGLs markets. These operations contain approximately 900 miles of NGLs pipelines, primarily related to its Mariner systems located in the northeast and southwest United States. Terminalling services are facilitated by approximately 5 million barrels of NGLs storage capacity, including approximately 1 million barrels of storage at its Nederland, Texas terminal facility and 3 million barrels at its Marcus Hook, Pennsylvania terminal facility (the “Marcus Hook Industrial Complex”). These operations also carry out Sunoco Logistics’ NGLs blending activities, including utilizing its patented butane blending technology.

In November 2016, ETP purchased a crude oil acquisition and marketing business from Vitol, with operations based in the United States.Permian Basin, Texas. Included in the acquisition was a significant acreage dedication from an investment-grade Permian producer.

ETP’s other operations and investments include the following:

Sunoco LP is a wholesale distributor of motor fuels and other petroleum products which Sunoco LP supplies to its retail operations, to third-party dealers and distributors, to independent operators of consignmentcommission agent locations and other consumers of motor fuel. Also included in the wholesale operations are transmix processing plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain (primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to salable products of gasoline and diesel.

Sunoco LP is the exclusive wholesale supplier of the iconic Sunoco brandedSunoco-branded motor fuel, supplying an extensive distribution network of approximately 5,3355,322 Sunoco-branded company and third-party operated locations throughout the East Coast, Midwest South Central and Southeast regions of the United States, including approximately 235245 company operated Sunoco-branded Stripes locations in Texas. Sunoco LP believes it is one of the largest independent motor fuel distributors by gallons in Texas and one of the largest distributors of Chevron, Exxon, Shell and Valero branded motor fuel in the United States. In addition to distributing motor fuels, Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it leases or subleases.

Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distribute it across more than 30 states throughout the East Coast, Midwest, South Central and Southeast regions of the United States, as well as Hawaii to approximately:

As of December 31, 2016,2017, prior to the closing of the amended and restated purchasing agreement with 7-Eleven, Sunoco LP’s retail operationssegment operated approximately 1,3451,348 convenience stores and retail fuel outlets. OurSunoco LP’s retail convenience stores operateoperates under several brands, including Sunoco’sits proprietary brands Stripes, APlus, and Aloha Island Mart, and offer a broad selection of food, beverages, snacks, grocery and non-food merchandise, motor fuel and other services. We haveSunoco LP has company operated sites in more than 20 states, with a significant presence in Texas, Pennsylvania, New York, Florida, Virginia and Hawaii.

As of December 31, 2016,2017, Sunoco LP operated approximately 740746 Stripes convenience stores in Texas, New Mexico, Oklahoma and Louisiana. Each store offers a customized merchandise mix based on local customer demand and preferences. Sunoco LP has built approximately 255265 large-format convenience stores from January 2000 through December 31, 2016.2017. Sunoco LP has implemented ourits proprietary, in-house Laredo Taco Company restaurant concept in approximately 470 Stripes convenience stores and intend to implement it in all newly constructed477 Stripes convenience stores. Sunoco LP also owns and operates ATM and proprietary money order systems in most Stripes stores and provideprovides other services such as lottery, prepaid telephone cards, wireless services and car washes.

As of December 31, 2016,2017, Sunoco LP operated approximately 445441 retail convenience stores and fuel outlets, primarily under Sunoco’sits proprietary and iconic Sunoco fuel brand, and principally located in Pennsylvania, New York and Florida, including approximately 400404 APlus convenience stores. Sunoco Retail's convenience stores offer a broad selection of food, beverages, snacks, grocery, and non-food merchandise, as well as motor fuel and other services such as ATM's, money orders, lottery, prepaid telephone cards, and wireless services.

As of December 31, 2016,2017, Sunoco LP operated approximately 160161 MACS and Aloha convenience stores and fuel outlets in Virginia, Maryland, Tennessee, Georgia, and Hawaii offering merchandise, food service, motor fuel and other services. As of December 31, 2016,2017, MACS operated approximately 110 company-operated107 retail convenience stores and Aloha operated approximately 5054 Aloha, Shell, and Mahalo branded fuel stations.

The descriptions below include summaries of significant assets within ETP’s operations. Amounts, such as capacities, volumes and miles included in the descriptions below are approximate and are based on information currently available; such amounts are subject to change based on future events or additional information.

The following details the assets in ETP’s operations:

The following details pipelines and storage facilities in ETP’s intrastate transportation and storage operations:

The following information describes ETP’s principal intrastate transportation and storage assets:

The following information describes ETP’s principal interstate transportation and storage assets:

The following details ourETP’s assets in theits midstream operations:

The following information describes ourETP’s principal midstream assets:

The following details ETP’sthe assets in the liquidsETP’s NGL and refined products transportation and services operations:

The following information describes ETP’s principal liquidsNGL and refined products transportation and services assets:

The following details the assetsETP’s pipelines and terminals in ETP’s investment in Sunoco Logistics:its crude oil transportation and services operations:

Sunoco Logistics’ETP’s crude oil pipelines consist of approximately 6,1009,358 miles of crude oil trunk and gathering pipelines in the southwest and midwest United States, including Sunoco Logistics’ETP’s wholly-owned interests in West Texas Gulf, and Permian Express Terminal LLC (“PET”), and a controlling financial interest in Mid-Valley Pipeline Company ("Mid-Valley"(“Mid-Valley”). Additionally, Sunoco LogisticsETP has equity ownership interests in two crude oil pipelines. Sunoco Logistics’

ETP’s crude oil pipelines provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading hubs located in Midland, Colorado City and Longview, Texas. Sunoco Logistics’ETP’s crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil to a number of refineries.

Sunoco Logistics’ETP’s crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil primarily in the mid-continent United States. The operations are conducted using Sunoco Logistics’ETP’s assets, which include approximately 370 crude oil transport trucks and approximately 150 crude oil truck unloading facilities, as well as third-party truck, rail and marine assets. Specifically, the crude oil acquisition and marketing activities include:

ETP owns and operates a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, dehydration and BTU management. ETP’s contract treating services are primarily located in Texas, Louisiana and Arkansas.

ETP’s Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. ETP also earns revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2016,2017, ETP owned or controlled approximately 772766 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky, Tennessee, 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. ETP’s subsidiary, Materials Handling Solutions, LLC, owns and operates facilities for industrial customers on a fee basis. During 2014, ETP’s coal reserves located in the San Juan basin were depleted and ETP’s associated coal royalties revenues ceased.

The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.216.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility willwould become a bi-directional facility capable of exporting and importing LNG. BGShell is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project willwould 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.

ETP has received its wetlands permits from the U.S.United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.

The following details the assets of Sunoco LP:

Lake Charles LNG, a wholly-owned subsidiary of ETE, owns a LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a run rate send out capacity of 1.8 Bcf/day.

LCL, an entity owned 60% by ETE and 40% by ETP, is in the process of developing the liquefaction project in conjunction with BG pursuant to a project development agreement entered into in September 2013 and scheduled to expire at the end of February 2017, subject to the parties’ right to mutually extend the term. Pursuant to this agreement, each of LCL and BG are obligated to pay 50% of the development expenses for the liquefaction project, subject to reimbursement by the other party if such party withdraws from the project prior to both parties making an affirmative FID to become irrevocably obligated to fully develop the project, subject to certain exceptions. The liquefaction project is expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.216.45 metric tonnes per annum. Once completed, the liquefaction project will enable LCL to liquefy domestically produced natural gas and export it as LNG. By adding the new liquefaction facility and integrating with the existing LNG regasification/import facility, the enhanced facility will become a bi-directional facility capable of exporting and importing LNG. BG is the sole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the regasification capacity regardless of whether it actually utilizes such capacity pursuant to a regasification services agreement that terminates in 2030. The liquefaction project is expected to be constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG and the remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.

Ac currently provided in theThe liquefaction project development agreement, the constructionis expected to consist of three LNG trains with a combined design nameplate outlet capacity of 16.45 metric tonnes per annum. Once completed, the liquefaction project is subjectwill enable LCL to each of LCLliquefy domestically produced natural gas and BG making an affirmative FID to proceed withexport it as LNG. By adding the project, which decision is in the sole discretion of each party. In the event an affirmative FID is made by both parties, LCL and BG will enter into several agreements related to the project, including a liquefaction services agreement pursuant to which BG will pay LCL for liquefaction services on a tolling basis for a minimum 25-year term with evergreen extension options for 20 years. In addition, a subsidiary of BG, a highly experienced owner and operator of LNG facilities, would oversee construction of thenew liquefaction facility and upon completionintegrating with the existing LNG regasification/import facility, the enhanced facility would become a bi-directional facility capable of construction, manageexporting and importing LNG. Shell is the operationssole customer for the existing regasification facility and is obligated to pay reservation fees for 100% of the liquefaction facility on behalfregasification capacity regardless of LCL. In the eventwhether it actually utilizes such capacity pursuant to a regasification services agreement that each of LCL and BG will make an affirmative FIDterminates in 2017, construction of the2030. The liquefaction project would commence immediately thereafter in order to place the first and secondbe constructed on 440 acres of land, of which 80 acres are owned by Lake Charles LNG trains in service in 2022 and the train in service in early 2023.remaining acres are to be leased by LCL under a long-term lease from the Lake Charles Harbor and Terminal District.

The export of LNG produced by the liquefaction project from the U.S. willUnited States would be undertaken under long-term export authorizations issued by the DOE to Lake Charles Exports, LLC (“LCE”), which is currently a jointly owned subsidiary of BG and ETP and following FID, will be 100% owned by BG.LCL. In July 2011, LCEMarch 2013, LCL obtained a DOE authorization to export LNG to countries with which the U.S.United States has or will have Free Trade Agreements (“FTA”) for trade in natural gas (the “FTA Authorization”).  In August 2013, LCEJuly 2016, LCL also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”).  The FTA Authorization and Non-FTA Authorization have 25- and 20-year terms, respectively. In January 2013, LCL filed for a secondary, non-cumulative FTA and Non-FTA Authorization to be held by LCL. FTA Authorization was granted in March 2013 and we expect the DOE to issue the Non-FTA Authorization to LCL in due course.

In addition, weWe have received our wetlands permits from the U.S.United States Army Corps of Engineers (“USACE”) to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles LNG facilities.

The business of providing natural gas gathering, compression, treating, transporting, storing and marketing services is highly competitive. Since pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage operations are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.

We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and marketing portions of our business. Our competitors include major integrated oil companies, interstate

In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

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.

In markets served by our products and crude oil pipelines, we face competition withfrom other pipelines.pipelines as well as rail and truck transportation. Generally, pipelines are the lowest cost method for long-haul, overland movement of products and 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.

We also faceWith respect to competition among common carrierfrom other pipelines, carrying crude oil. This competition is based primarily onthe primary competitive factors consist of transportation charges, access to crude oil supply and market demand. Similar to pipelines carrying products, the high capital costs deter competitors for the crude oil pipeline systems from building new pipelines. Competitive factors in crude oil purchasing and marketing include price and contract flexibility, quantity and quality of services, and accessibility to end markets.

Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

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 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.

In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities.

Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering system.

We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

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.

FERC regarding our cost of service, may also be subject to review in the courts. OnIn December 23, 2016, FERC issued ana Notice of Inquiry Regarding the Commission’s Policy for Recovery of Income Tax Credits.Costs. FERC is seeking commentrequested comments regarding how to address any double recovery resulting from the FERC’sCommission’s current income tax allowance and rate of return policies. The comment period with respect to the proposed rules extends untilnotice of inquiry ended on April 7, 2017. The outcome of the inquiry is still pending.

EPAct 1992 required FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPIFG. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2011 and ending June 30, 2016, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPIFG plus 2.65%. Beginning July 1, 2016, the indexing method provided for annual changes equal to the change in PPIFG plus 1.23%. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior 2 years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules extends untilended on March 17, 2017. FERC has taken no further action on the proposed rule to date.

In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.

Regulation of Pipeline Safety.  Our pipeline operations are subject to regulation by the DOT, through the PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA,

as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas (“HCAs”), which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Failure

The HLPSA and NGPSA and HLPSA werehave been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which re-authorized and the federal pipelineProtecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”). The 2011 Pipeline Safety Act increased the penalties for safety programsviolations, 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 through 2015 and increased pipeline safety regulation. Among other things, the legislationfor 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; permitted the DOT Secretaryactions. Effective April 27, 2017, to mandate automatic or remote controlled shut off valves on new or entirely replaced pipelines; required the DOT Secretary to evaluate whether integrity management system requirements should be expanded beyond HCAs; and providedaccount for regulation of carbon dioxide transported by pipeline in a gaseous state and requires the DOT Secretary to prescribe minimum safety regulations for such transportation. Effective August 1, 2016,inflation, those maximum civil penalties were increased to $205,638 per violation$209,002 per day, with a maximum of approximately $2 million$2,090,022 for a series of violations, to account for inflation. In addition, the Protecting Our Infrastructure of Pipelines and Enhancingviolations. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 (“PIPES Act) reauthorizedAct 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 federalagency’s expanded authority to address unsafe pipeline safety programs of PHMSA through 2019.conditions or practices that pose an imminent hazard to life, property, or the environment.

In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which we conduct operations typically have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines. Under such state regulatory programs, states have the authority to conduct pipeline inspections, to investigate accidents and to oversee compliance and enforcement, safety programs and record maintenance and reporting. Congress, PHMSA and individual states may pass or implement additional safety requirements that could result in increased compliance costs for us and other companies in our industry. For example, federal construction, maintenance and inspection standards under the NGPSA that apply to pipelines in relatively populated areas may not apply to gathering lines running through rural regions. This “rural gathering exemption” under the NGPSA presently exempts substantial portions of our gathering facilities located outside of cities, towns or any area designated as residential or commercial from jurisdiction under the NGPSA, but does not apply to our intrastate natural gas pipelines. In recent years, the PHMSA has considered changes to this rural gathering exemption, including publishing an advance notice of proposed rulemaking relating to gas pipelines in 2011, in which the agency sought public comment on possible changes to the definition of “high consequence areas” and “gathering lines” and the strengthening of pipeline integrity management requirements. In April 2016, pursuant to one of the requirements of the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that, among other things, would expand integrity management requirementscertain 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 impose newthus excluded from certain pressure testing requirements on currently regulated gas transmission pipelines. The proposal would also significantly expand the regulation ofobligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and require certain onshore and offshore gathering lines subjecting previously unregulated pipelinesin Class I areas to requirements regardingcomply with damage prevention, corrosion control, public education, programs, maximum allowable operating pressureMAOP limits, line markers and other requirements.emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines. PHMSA has not yet finalized the March 2016 proposed rulemaking.

In January 2017, PHMSA issued a final rule amending federal safety standards for hazardous liquid pipelines. The final rule is the latest step in a lengthy rulemaking process that began in 2010 with a request for comments and continued with publication of a rulemaking proposal in October 2015. The general effective date of this final rule is six months from publication in the Federal Register, but it is currently subject to further administrative review in connection with the transition of Presidential administrations.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 new regulations on January 23, 2017, on operator qualification, cost recovery, accident and incident notification and other pipeline safety changes. These new regulationschanges that are effective March 24, 2017.now effective. These regulations are also subject, however, to potential further review in connection with the transition of Presidential

administrations. Historically, our pipeline safety costs have not had a material adverse effect on our business or results of operations but there is no assurance that such costs will not be material in the future, whether due to elimination of the rural gathering exemption or otherwise due to changes in pipeline safety laws and regulations.

In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the Federal Occupational Safety and Health Administration (“OSHA”)federal OSHA’s Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one or more state regulators, including the Texas Railroad Commission, have in the recent past,years, expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with hazardous liquid pipeline safety requirements. These recent actions by PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators; however, toTo the extent that such legal challengesthese actions are unsuccessful,pursued by PHMSA, midstream operators of NGL fractionation facilities and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in some instances, may be significant.

We have implemented procedures designed to ensure that all governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. 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 other unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.

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 nonhazardousnon-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 in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the United States District Court for the District of Columbia on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes such as these examples in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense

We currently own or lease sites that have been used over the years by prior owners orand lessees and by us for various activities related to gathering, processing, storage and transmission of natural gas, NGLs, crude oil and products. Waste disposal practices within the oil and gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on or under various sites during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.

The Partnership is subject to extensive and frequently changing federal, tribal, state and local laws and regulations, including those relating to the discharge of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and composition of fuels. These laws and regulations require environmental assessment and remediation efforts at many of Sunoco, Inc.’s facilities and at formerly owned or third-party sites. Accruals for these environmental remediation activities amounted to $324$284 million and $344$289 million at December 31, 20162017 and 2015,2016, respectively, which is included in the total accruals above. These legacy sites that are subject to environmental assessments include formerly owned terminals and other logistics assets, retail sites that are no longer operated by Sunoco, Inc., closed and/or sold refineries and other formerly owned sites. In December 2013, a wholly-owned captive insurance company was established for these legacy sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. As of December 31, 20162017 the captive insurance company held $226$207 million of cash and investments.

The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.

Under various environmental laws, including the RCRA, the Partnership has initiated corrective remedial action at certain of its facilities, and 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

In addition to the probable and estimable losses which have been recorded, management believes it is reasonably possible (that is, it is less than probable but greater than remote) that additional environmental remediation losses will be incurred. At December 31, 2016,2017, the aggregate of such additional estimated maximum reasonably possible losses, which relate to numerous individual sites, totaled approximately $5 million, which amount is in excess of the $345$372 million in environmental accruals recorded on December 31, 2016.2017. This estimate of reasonably possible losses comprises estimates for remediation activities at current logistics and retail assets, and in many cases, reflects the upper end of the loss ranges which are described above. Such estimates include potentially higher contractor costs for expected remediation activities, the potential need to use more costly or comprehensive remediation methods and longer operating and monitoring periods, among other things.

In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely extend over many years, but management can provide no assurance that it would be over many years. If changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time.  As a result, from time to time, significant charges against income for environmental remediation may occur. And while management does not believe that any such charges would have a material adverse impact on the Partnership’s consolidated financial position, it can provide no assurance.

Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue through 2025 is $7$5 million, which is included in the total environmental accruals mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by customers and former customers. 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.

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.

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.

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.

As of December 31, 2016,2017, ETE and its consolidated subsidiaries employed an aggregate of 30,99229,486 employees, 1,7601,544 of which are represented by labor unions. We and our subsidiaries believe that our relations with our employees are satisfactory.

We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and supplements thereto with the SEC. From time to time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-732-0330. In addition, the SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC. Information contained on our website is not part of this report.

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to our structure as a limited partnership, our industry and our company could materially impact our future performance and results of operations. We have provided below a list of these risk factors that should be reviewed when considering an investment in our securities. ETP, Panhandle PennTex, Sunoco Logistics and Sunoco LP file Annual Reports on Form 10-K that include risk factors that can be reviewed for further information. The risk factors set forth below, and those included in ETP’s, Panhandle’s PennTex’s, Sunoco Logistics’ and Sunoco LP’s Annual Reports, are not all the risks we face and other factors currently considered immaterial or unknown to us may impact our future operations.

The Parent company’s principal source of our earnings and cash flow is cash distributions from ETP PennTex, Sunoco LP and Sunoco Logistics via the Class H Units.LP. Therefore, the amount of distributions we are currently able to make to our Unitholders may fluctuate based on the level of distributions ETP PennTex,and Sunoco LP or Sunoco Logistics makesmake to their partners. ETP PennTex,and Sunoco LP or Sunoco Logistics may not be able to continue to make quarterly distributions at their current level or increase their quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our Unitholders if ETP PennTex,or Sunoco LP or Sunoco Logistics increases or decreases distributions to us, the timing and amount of such increased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by ETP PennTex,or Sunoco LP or Sunoco Logistics to us.

Our ability to distribute cash received from ETP PennTex,and Sunoco LP and Sunoco Logistics to our Unitholders is limited by a number of factors, including:

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.

We do not have any significant assets other than our partnership interests in ETP and Sunoco LP and our LNG business. Our interest in ETP includes Class H Units, for which distributions to us are based on a percentage of the general partner interest and incentive distribution right in Sunoco Logistics. As a result, our cash flow depends on the performance of ETP PennTex,and Sunoco LP and Sunoco Logistics and their respective subsidiaries and ETP’s and Sunoco LP’s ability to make cash distributions to us, which is dependent on the results of operations, cash flows and financial condition of ETP PennTex, Sunoco LP and Sunoco Logistics.LP.

The amount of cash that ETP PennTex,and Sunoco LP and Sunoco Logistics can distribute to their partners, including us, each quarter depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter and will depend upon, among other things:

In addition, the actual amount of cash that ETP PennTex,and Sunoco LP and Sunoco Logistics will have available for distribution will also depend on other factors, such as:

ETE does not have any control over many of these factors, including the level of cash reserves established by the board of directors and ETP’s General Partners. Accordingly, we cannot guarantee that ETP PennTex,and Sunoco LP or Sunoco Logistics will have sufficient available cash to pay a specific level of cash distributions to its partners.

Furthermore, Unitholders should be aware that the amount of cash that ETP and Sunoco LP have available for distribution depends primarily upon cash flow and is not solely a function of profitability, which is affected by non-cash items. As a result, ETP and Sunoco LP may declare and/or pay cash distributions during periods when they record net losses. Please read “Risks Related to the Businesses of Energy Transfer Partners”our Subsidiaries” included in this Item 1A for a discussion of further risks affecting ETP’s and Sunoco LP’s ability to generate distributable cash flow.

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:

In addition, ETP and Sunoco LP may sell an unlimited number of limited partner interests without the consent of the respective Unitholders, which will dilute existing interests of the respective Unitholders, including us. The issuance of additional Common Units or other equity securities by ETP or Sunoco LP will have essentially the same effects as detailed above.

The partnership agreements of ETP Sunoco Logistics, PennTex and Sunoco LP allow each partnership to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by each respective partnership will have the following effects:

The payment of distributions on any additional units issued by ETP PennTex,and Sunoco LP and Sunoco Logistics 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.

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, 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.

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 General Partner may transfer its general partner interest to a third party without the consent of the Unitholders. Furthermore, the members of our General Partner may transfer all or part of their ownership interest in our General Partner to a third party without the consent of the Unitholders. Any new owner or owners of our General Partner or the general partner of the General Partner would be in a position to replace the directors and officers of our General Partner with its own choices and to control the decisions made and actions taken by the board of directors and officers.

We rely on the services of key personnel of ETP, including the ongoing involvement and continued leadership of Kelcy L. Warren, one of the founders of ETP’s midstream business. Mr. Warren has been integral to the success of ETP’s midstream and intrastate transportation and storage businesses because of his ability to identify and develop strategic business opportunities. Losing the leadership of Mr. Warren could make it difficult for ETP to identify internal growth projects and accretive acquisitions, which could have a material adverse effect on ETP’s ability to increase the cash distributions paid on its partnership interests.

ETP’s executive officers that provide services to us pursuant to a shared services agreement allocate their time between us and ETP. To the extent that these officers face conflicts regarding the allocation of their time, we may not receive the level of attention from them that the management of our business requires. If ETP is unable to provide us with a sufficient number of personnel with the appropriate level of technical accounting and financial expertise, our internal accounting controls could be adversely impacted.

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.

ETE indirectly owns all of the IDRs of ETP and Sunoco LP. Additionally, through its ownership of ETP Class H units and a 0.1% interest in Sunoco Logistics’ general partner, ETE is entitled to receive 90.15% of the cash distributions related to the IDRs of Sunoco Logistics, while ETP is entitled to receive the remaining 9.85% of such cash distributions. These IDRs entitle the holder to receive increasing percentages of total cash distributions made by each of ETP Sunoco LP and Sunoco LogisticsLP as such entity reaches established target cash distribution levels as specified in its partnership agreement. ETE currently receives its pro rata share of cash distributions from ETP and Sunoco LP based on the highest sharing level of 48% and 50% in respect of the ETP IDRs and Sunoco LP IDRs, respectively. ETE and ETP currently receive their pro rata share of cash distributions from Sunoco Logistics based on the highest sharing level of 48% in respect of the Sunoco Logistics IDRs.

A decrease in the amount of distributions by ETP to ETE to less than $0.4125$0.2638 per unit per quarter would reduce ETE’s percentage of the incremental cash distributions from ETP above $0.3175$0.0958 per unit per quarter from 48% to 23%35%, and a decrease in the amount

ETP’s PennTex’s, Sunoco Logistics’ and Sunoco LP’s levels of indebtedness affect their operations in several ways, including, among other things:

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:

A downgrade of our credit ratings might increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:

Neither our partnership agreement nor the partnership agreements of our subsidiaries, including ETP Sunoco Logistics, PennTex and Sunoco LP, prohibit our subsidiaries from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.

ETP plans to fund its growth capital expenditures, including any new future pipeline construction projects and improvements or repairs to existing facilities that ETP may undertake, with proceeds from sales of ETP’s debt and equity securities and borrowings under its revolving credit facility; however, ETP cannot be certain that it will be able to issue debt and equity securities on terms satisfactory to it, or at all. In addition, ETP may be unable to obtain adequate funding under its current revolving credit facility because ETP’s lending counterparties may be unwilling or unable to meet their funding obligations. If ETP is unable to finance its expansion projects as expected, ETP could be required to seek alternative financing, the terms of which may not be attractive to ETP, or to revise or cancel its expansion plans.

A significant increase in ETP’s indebtedness that is proportionately greater than ETP’s issuance of equity could negatively impact ETP’s credit ratings or its ability to remain in compliance with the financial covenants under its revolving credit agreement, which could have a material adverse effect on ETP’s financial condition, results of operations and cash flows.

In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates. Approximately $11.60$9.86 billion of our consolidated debt as of December 31, 20162017 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.

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 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.

Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.

Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner. Our partnership agreement allows the general partner to incur obligations on our behalf that are expressly non-recourse to the general partner. The general partner has entered into such limited recourse obligations in most instances involving payment liability and intends to do so in the future.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

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, 2016,2017, the directors and executive officers of our General Partner owned approximately 27% of our Common Units.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and ETP and Sunoco LP and their respective limited partners, on the other hand. The directors and officers of ETP’s and Sunoco LP’s General Partners have fiduciary duties to manage ETP and Sunoco LP, respectively, in a manner beneficial to us. At the same time, the General Partners have fiduciary duties to manage ETP and Sunoco LP in a manner beneficial to ETP and Sunoco LP and their respective limited partners. The boards of directors of ETP’s and Sunoco LP’s General Partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.

For example, conflicts of interest with ETP and Sunoco LP may arise in the following situations:

Conflicts of interest may arise because of the relationships among ETP, Sunoco LP, their general partners and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our General Partner’s directors are also directors and officers of ETP’s general partner or Sunoco LP’s general partner, and have fiduciary duties to manage the respective businesses of ETP and Sunoco LP in a manner beneficial to ETP, Sunoco LP and their respective Unitholders. The resolution of these conflicts may not always be in our best interest or that of our Unitholders.

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 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:

Our partnership agreement requires the general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, our partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable

Since our cash flows consist exclusively of distributions from ETP and Sunoco LP,our subsidiaries, risks to the businesses of ETP and Sunoco LPour subsidiaries are also risks to us. We have set forth below risks to the businesses of ETP and Sunoco LP,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.

Certain of ETP’s and Sunoco Logistics’ joint ventures have their own governing boards, and ETP or Sunoco Logistics may not control all of the decisions of those boards. Consequently, it may be difficult or impossible for ETP or Sunoco Logistics to cause the joint venture entity to take actions that ETP or Sunoco Logistics believes would be in their or the joint venture’s best interests. Likewise, ETP or Sunoco Logistics may be unable to prevent actions of the joint venture.

The risks of nonpayment and nonperformance by ETP’s and Sunoco LP’s respective customers are a major concern in their respective businesses. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. ETP and Sunoco LP are subject to risks of loss resulting from nonpayment or nonperformance by their respective customers, especially during the current low commodity price environment impacting many oil and gas producers. As a result, the current commodity price volatility and the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by ETP’s and Sunoco LP’s customers. To the extent one or more of our customers is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our Unitholders. Any substantial increase in the nonpayment and nonperformance by ETP’s or Sunoco LP’s customers could have a material adverse effect on ETP’s or Sunoco LP’s respective results of operations and operating cash flows.

From time to time, ETP and Sunoco LP have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative financial instruments and other risk management mechanisms and by their trading, marketing and/or system optimization activities. To the extent that either ETP or Sunoco LP hedges its commodity price and interest rate exposures, it foregoes the benefits it would otherwise experience if commodity prices or interest rates were to change favorably. In addition, even though monitored by management, ETP’s and Sunoco LP’s derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to ETP’s or Sunoco LP’s physical or financial positions, or internal hedging policies and procedures are not followed.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically (whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge.

In addition, even though monitored by management, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions or hedging policies and procedures are not followed.

ETP’s ability to operate its pipeline systems and terminal facilities on certain lands owned by third parties, including lands held in trust by the United States for the benefit of a Native American tribe, will depend on their success in maintaining existing rights-of-way and obtaining new rights-of-way on those lands. Securing extensions of existing and any additional rights-of-way is also critical to ETP’s ability to pursue expansion projects. ETP cannot provide any assurance that they will be able to acquire new rights-of-way or maintain access to existing rights-of-way upon the expiration of the current grants or that all of the rights-of-way will be obtainable in a timely fashion. Transwestern’s existing right-of-way agreements with the Navajo Nation, Southern Ute, Pueblo of Laguna and Fort Mojave tribes extend through November 2029, September 2020, December 2022 and April 2019, respectively. ETP’s financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.

Further, whether ETP has the power of eminent domain for its pipelines varies from state to state, depending upon the type of pipeline and the laws of the particular state. In either case, ETP must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect ETP’s business if they were to lose the right to use or occupy the property on which their pipelines are located. For example, following a recent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. Any loss of rights with respect to ETP’s real property, through its inability to renew right-of-way contracts or otherwise, could have a material adverse effect on its business, results of operations, financial condition and ability to make cash distributions.

In addition, Sunoco LP does not own all of the land on which their retail service stations are located. Sunoco LP has rental agreements for approximately 34.7%35.2% of the company-operated retail service stations where Sunoco LP currently controls the real estate and has rental agreements for certain logistics facilities. As such, Sunoco LP is subject to the possibility of increased costs under rental agreements with landowners, primarily through rental increases and renewals of expired agreements. Sunoco LP is also subject to the risk that such agreements may not be renewed. Additionally, certain facilities and equipment (or parts thereof) used by Sunoco LP are leased from third parties for specific periods. Sunoco LP’s inability to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on its financial condition, results of operations and cash flows.

ETP and Sunoco LP have strategies that contemplate growth through the development and acquisition of a wide range of midstream, retail and wholesale fuel distribution assets and other energy infrastructure assets while maintaining strong balance sheets. These strategies include constructing and acquiring additional assets and businesses to enhance their ability to compete effectively and diversify their respective asset portfolios, thereby providing more stable cash flow. ETP and Sunoco LP regularly consider and enter into discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that ETP and Sunoco LP believe will present opportunities to realize synergies and increase cash flow.

Consistent with their strategies, managements of ETP and Sunoco LP may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve ETP and Sunoco LP management’s participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which ETP and Sunoco LP believe it is the only party or one of a very limited number of potential buyers

in negotiations with the potential seller. We cannot assure that ETP’s or Sunoco LP’s acquisition efforts will be successful or that any acquisition will be completed on favorable terms.

In addition, ETP and Sunoco LP are experiencing increased competition for the assets they purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in ETP or Sunoco LP losing to other bidders more often or acquiring assets at higher prices, both of which would limit ETP’s and Sunoco LP’s ability to fully execute their respective growth strategies. Inability to execute their respective growth strategies may materially adversely impact ETP’s and Sunoco LP’s results of operations.

As of December 31, 2016,2017, our consolidated balance sheets reflected $6.74$4.77 billion of goodwill and $5.99$6.12 billion of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to total capitalization.

ETP’s and Sunoco LP’s results of operations and their ability to grow and to increase distributions to Unitholders will depend in part on their ability to make acquisitions that are accretive to their respective distributable cash flow.

ETP and Sunoco LP may be unable to make accretive acquisitions for any of the following reasons, among others:

Furthermore, even if ETP or Sunoco LP consummates acquisitions that it believes will be accretive, those acquisitions may in fact adversely affect its results of operations or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that ETP or Sunoco LP may:

If ETP and Sunoco LP consummate future acquisitions, their respective capitalization and results of operations may change significantly. As ETP and Sunoco LP determine the application of their funds and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that ETP and Sunoco LP will consider.

In February 2017, the Department of the Army delivered an easement to Dakota Access allowing the Department of Justice,pipeline to cross Lake Oahe. The SRST and Cheyenne River Sioux Tribe (“CRST”) (which had intervened in the Department of the Interior released a joint statement stating that the USACE would not grant the easement for the land adjacentlawsuit brought by SRST), amended their complaints to Lake Oahe until the federal departments completed a review of the SRST’sincorporate religious freedom and other claims in its lawsuit with respect to the USACE’s compliance with certain federal statutes in connection with its activities related to the granting of the permits. The SRST appealed the denial of the preliminary injunction to the U.S. Court of Appeals for the D.C. Circuittreaties and filed an emergency motion for an injunction pending the appeal to the U.S. District Court. The U.S. District Court denied SRST’s emergency motion for an injunction pending the appeal. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statues governing the use of government property. The D.C. Circuit denied the SRST’s application for a stay pending appeal and later dismissed the SRST’s appeal of the denied TRO.

The prices for natural gas, NGLs and crude oil (including refined petroleum products) reflect market demand that fluctuates with changes in global and U.S.United States economic conditions and other factors, including:

In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and we expect this volatility to continue.

Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs or crude oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGLNGLs and crude oil commodities could materially affect our profitabilityprofitability.

We experience competition in all of our business segments. With respect to ETP’s midstream operations, ETP competes for both natural gas supplies and customers for its services. Competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas.

ETP’s natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service, access to sources of supply and the flexibility and reliability of service. Natural gas

and NGLs also competescompete with other forms of energy, including electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits also affects competitive outcomes.

In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.

ETP’s crude oil and refined products pipeline operations face significant competition from other pipelines for large volume shipments. These operations also face competition from trucks for incremental and marginal volumes in areas served by Sunoco Logistics’ pipelines. Further, our refined product terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

ETP may be unable to retain or replace existing midstream, transportation, terminalling and storage customers or volumes due to declining demand or increased competition in crude oil, natural gas and NGL markets, which would reduce revenues and limit future profitability.

The retention or replacement of existing customers and the volume of services that ETP provides at rates sufficient to maintain or increase current revenues and cash flows depends on a number of factors beyond our control, including the price of and demand for crude oil, natural gas, and NGLs in the markets we serve and competition from other service providers.

A significant portion of ETP’s sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of these customers also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in natural gas sales markets primarily on the basis of price.

ETP also receives a substantial portion of revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a substantial portion of their services are sold under long-term contracts for reserved service, they also provide service on an unreserved or short-term basis. Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production resulting in less use of services, while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may attract our customers’ business. If demand declines or competition increases, we may not be able to sustain existing levels of unreserved service or renew or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.

Revenue from ETP’s NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. ETP receives substantially all of their transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are connected only to their transportation system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under dedicated contracts and lower demand for our services. In addition, ETP’s refined products storage revenues

The volume of crude oil and products transported through ETP’s oil pipelines and terminal facilities depends on the availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or products could lead to a decline in drilling activity, production and refining of crude oil, or import levels in these areas. A period of sustained increases in the price of crude oil or products supplied from or delivered to any of these areas could materially reduce demand for crude oil or products in these areas. In either case, the volumes of crude oil or products transported in our oil pipelines and terminal facilities could decline.

The loss of existing customers by ETP’s midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services customers purchase from them, or their inability to attract new customers and service volumes would negatively affect revenues, be detrimental to growth, and adversely affect results of operations.

In order to maintain or increase throughput levels on ETP’s gathering systems and transportation pipeline systems and asset utilization rates at our treating and processing plants, ETP must continually contract for new natural gas supplies and natural gas transportation services.

A substantial portion of ETP’s assets, including its gathering systems and processing and treating plants, are connected to natural gas reserves and wells that experience declining production over time. ETP’s gas transportation pipelines are also dependent upon natural gas production in areas served by our gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. ETP may not be able to obtain additional contracts for natural gas supplies for its natural gas gathering systems, and may be unable to maintain or increase the levels of natural gas throughput on its transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to its transportation pipelines or markets to which ETP’s systems connect. ETP has no control over the level of drilling activity in its areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline. In addition, ETP has no control over producers or their production and contracting decisions.

While a substantial portion of ETP’s services are provided under long-term contracts for reserved service, it also provides service on an unreserved basis. The reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities may decline and may not be replaced by other sources of supply. A decrease in development or production activity could cause a decrease in the volume of unreserved services ETP provides and a decrease in the number and volume of its contracts for reserved transportation service over the long run, which in each case would adversely affect revenues and results of operations.

If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be materially and adversely affected.

For a portion of the natural gas gathered on ETP’s systems, they purchase natural gas from producers at the wellhead and then gather and deliver the natural gas to pipelines where they typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins realized under these arrangements decrease in periods of low natural gas prices.

ETP’s natural gas transportation, storage and NGL businesses depend, in part, on their customers’ ability to obtain access to pipelines to deliver gas to and receive gas from ETP. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third-party pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material adverse effect on ETP’s ability, and the ability of their customers, to transport natural gas to and from their pipelines and facilities and a corresponding material adverse effect on their transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from ETP’s s facilities affect the utilization and value of their storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on storage revenues.

Shippers using ETP’s oil pipelines and terminals are also dependent upon their pipelines and connections to third-party pipelines to receive and deliver crude oil and products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in ETP’s pipelines or through their terminals. Similarly, if additional shippers begin transporting volume over interconnecting oil pipelines, the allocations of pipeline capacity to ETP existing shippers on these interconnecting pipelines could be reduced, which also could reduce volumes transported in their pipelines or through their terminals. Allocation reductions of this nature are not infrequent and are beyond our control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could have a material adverse effect on ETP’s results of operations, financial position, or cash flows.

ETP’s results of operations and their ability to grow and to increase distributable cash flow per unit will depend, in part, on their ability to construct pipelines that are accretive to their respective distributable cash flow. ETP may be unable to construct pipelines that are accretive to distributable cash flow for any of the following reasons, among others:

Furthermore, even if ETP constructs a pipeline that it believes will be accretive, the pipeline may in fact adversely affect its results of operations or fail to achieve results projected prior to commencement of construction.

One of the ways that ETP has grown their business is through the construction of additions to existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline and related facilities (or the improvement and repair of existing facilities) involves numerous regulatory, environmental, political and legal uncertainties beyond ETP’s control and requires the expenditure of significant amounts of capital to be financed through borrowings, the issuance of additional equity or from operating cash flow. If ETP undertakes these projects, they may not be completed on schedule or at all or at the budgeted cost. A variety of factors outside ETP’s control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors may result in increased costs or delays

in construction. Cost overruns or delays in completing a project could have a material adverse effect on ETP’s results of operations and cash flows. Moreover, revenues may not increase immediately following the completion of a particular project. For instance, if ETP builds a new pipeline, the construction will occur over an extended period of time, but ETP may not materially increase its revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced by the project as well as ETP’s ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, ETP may construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve ETP’s expected investment return, which could adversely affect its results of operations and financial condition.

ETP relies on a limited number of producers for a significant portion of their natural gas supplies. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, ETP will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. ETP may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on ETP’s business, results of operations, and financial condition.

ETP relies on a limited number of major shippers to transport certain minimum volumes of natural gas on their respective pipelines. The failure of the major shippers on ETP’s or their joint ventures’ pipelines or of other key customers to fulfill their contractual obligations under these contracts could have a material adverse effect on the cash flow and results of operations of us, ETP or their joint ventures, as applicable, were unable to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

The principal manufacturers of components for ETP’s natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers and Ariel Corporation for compressors and frames. ETP’s reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. ETP also relies primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble its compression units. ETP does not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships.

The volume of crude oil transported through Sunoco Logistics’ETP’s crude oil pipelines and terminal facilities depends on the availability of attractively priced crude oil produced or received in the areas serviced by its assets. A period of sustained crude oil price declines could lead to a decline in drilling activity, production and import levels in these areas. Similarly, a period of sustained increases in the price of crude oil supplied from any of these areas, as compared to alternative sources of crude oil available to Sunoco Logistics’ETP’s customers, could materially reduce demand for crude oil in these areas. In either case, the volumes of crude oil transported

While Sunoco LogisticsETP 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 U.S.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 U.S.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. Much of theThe 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 Sunoco LogisticsETP could experience an interruption of supply or delivery or an increased cost of receiving crude oil, and could experience a decline in volumes received. Recent railcar accidents in Quebec, Alabama, North Dakota, Pennsylvania and Virginia, in each case involving trains carrying crude oil from the Bakken region, have led to increased legislative and regulatory scrutiny over the safety of transporting crude oil by rail. In 2015, the DOT, through the PHMSA, issued a rule implementing new rail car standards and railroad operating procedures. Changing operating practices, as well as new regulations on tank car standards and shipper classifications, could increase the time required to move crude oil from production areas of facilities, increase the cost of rail transportation, and decrease the efficiency of transportation of crude oil by rail, any of which could materially reduce the volume of crude oil received by rail and adversely affect our financial condition, results of operations, and cash flows.

Sunoco LogisticsETP utilizes both affiliate entities and third parties in the processing of its information and data. Breaches of its security measures or the accidental loss, inadvertent disclosure or unapproved dissemination of proprietary information or sensitive or confidential data about Sunoco LogisticsETP or its customers, including the potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose Sunoco LogisticsETP to a risk of loss or misuse of this information, result in litigation and potential liability for Sunoco Logistics,ETP, lead to reputational damage, increase compliance costs, or otherwise harm its business.

Sunoco LP is required to purchase refined products from third party sources, including the joint venture that acquired Sunoco, Inc.’s Philadelphia refinery. Sunoco LP may also need to contract for new ships, barges, pipelines or terminals which it has not historically used to transport these products to its markets. The inability to acquire refined products and any required transportation services at favorable prices may adversely affect Sunoco LP’s business and results of operations.

Sales of refined motor fuels account for approximately 84%93% of Sunoco LP’s total revenues and 55%62% of continuing operations gross profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and their ability to make or increase distributions to unitholders. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic, travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience declines in their profit margin if fuel distribution volumes decrease.

Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or other alternative-power vehicles could fundamentally change customers' shopping habits or lead to new forms of fueling destinations or new competitive pressures.

Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.

Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.

Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a material adverse effect on its business, financial condition, results of operations and cash available for distribution to unitholders.

Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following:

The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s business, financial condition, results of operations, cash flows and ability to make distributions to unitholders.

Sunoco LP believes that the success of convenience stores alongits operations is dependent, in part, on the U.S.-Mexico border increases their exposure to certain cross-border risks that could adversely affect its businesscontinuing favorable reputation, market value, and financial condition by lowering sales revenues.

volumes of motor fuel Sunoco LP distributes, which in close proximity to Mexico. These stores rely heavily upon cross-border traffic and commerce to drive sales volumes. Sales volumes at these stores could be impaired by a number of cross-border risks, any one of whichturn could have a material adverse effect on Sunoco LP’sits business, financial condition, and results of operations including the following:

The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-added, reliable services and to control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could attempt to buy directly from the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to unitholders.

The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and marked by ease of entry and constant change in the number and type of retailers offering products and services of the type soldwe and our independently operated commission agents and dealers sell in their stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores, motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades, several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry, particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.

In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse effect on its business, results of operations and cash available for distribution to unitholders.

Significant increases in wholesale cigarette costs and tax increases on cigarettes may have an adverse effect on unit demand for cigarettes. Cigarettes are subject to substantial and increasing excise taxes at both a state and federal level. Sunoco LP cannot predict whether this trend will continue into the future. Increased excise taxes may result in declines in overall sales volume and reduced gross profit percent, due to lower consumption levels and to a shift in consumer purchases from the premium to the non-premium or discount segments or to other lower-priced tobacco products or to the import of cigarettes from countries with lower, or no, excise taxes on such items.

Currently, major cigarette manufacturers offer rebates to retailers. Sunoco LP includes these rebates as a component of its gross margin from sales of cigarettes. In the event these rebates are no longer offered, or decreased, Sunoco LP’s wholesale cigarette costs will increase accordingly. In general, Sunoco LP attempts to pass price increases on to its customers. However, due to competitive pressures in our markets, it may not be able to do so. These factors could materially impact Sunoco LP’s retail price of cigarettes, cigarette unit volume and revenues, merchandise gross profit and overall customer traffic, which could in turn have a material adverse effect on Sunoco LP’s business and results of operations.

State laws regulate the sale of alcohol and cigarettes. A violation of or change in these laws could adversely affect Sunoco LP’s business, financial condition and results of operations because state and local regulatory agencies have the power to approve, revoke, suspend or deny applications for, and renewals of, permits and licenses relating to the sale of these products and can also seek other remedies. Such a loss or imposition could have a material adverse effect on Sunoco LP’s business and results of operations.

Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to unitholders.

Sunoco LP may be 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.stores or independently operated commission agent or dealer locations.

It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name recognition.

Sunoco LP has previously outsourced various functions related to its retail marketing business to third parties and expects to continue this practice with other functions in the future.

deception, could expose usit to a risk of loss or misuse of this information, result in litigation and potential liability for us,it, lead to reputational damage to the Sunoco Inc. brand, increase ourits compliance costs, or otherwise harm ourits business.

Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of ETP’s interstate pipelines to establish rates, to charge rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.

ETP is required to file tariff rates (also known as recourse rates) with the FERC that shippers may elect to pay for interstate natural gas transportation services. We may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. ETP must also file with the FERC all negotiated rates that do not conform to our tariff rates and all changes to our tariff or negotiated rates. The FERC must approve or accept all rate filings for us to be allowed to charge such rates.

The FERC may review existing tariffstariff rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against ETP and find that its rates were not just and reasonable or unduly discriminatory, the maximum rates customers could elect to pay ETP may be reduced and the reduction could have an adverse effect on our revenues and results of operations.

The costs of ETP’s interstate pipeline operations may increase and ETP may not be able to recover all of those costs due to FERC regulation of its rates. If ETP proposes to change its tariff rates, its proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit ETP’s proposed changes if ETP is unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. ETP also may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases, or ETP may be constrained by competitive factors from charging their tariff rates.

To the extent ETP’s costs increase in an amount greater than its revenues increase, or there is a lag between its cost increases and ability to file for and obtain rate increases, ETP’s operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. ETP cannot guarantee that its interstate pipelines will be able to recover all of their costs through existing or future rates.

The ability of interstate pipelines held in tax-pass-through entities, like ETP, to include an allowance for income taxes as a cost-of-service element in their regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. It is currently the FERC’s policy to permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential income tax liability on their public utility income attributable to all partnership or limited liability company interests, to the extent that the ultimate owners have an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Under the FERC’s policy, ETP thus remains eligible to include an income tax allowance in the tariff rates ETP charges for interstate natural gas transportation. On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax

Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. Following the 2017 Tax Cuts and Jobs Act being signed into law, filings have been made at FERC requesting that FERC require pipelines to lower their transportation rates to account for lower taxes. Following the effective date of the law, the FERC orders granting certificates to construct proposed pipeline facilities have directed pipelines proposing new rates for service on those facilities to re-file such rates so that the rates reflect the reduction in the corporate tax rate, and

FERC has issued an Inquiry Regardingdata requests in pending certificate proceedings for proposed pipeline facilities requesting pipelines to explain the Commission’s Policyimpacts of Recovery of Income Tax Credits. FERC is seeking comment regarding howthe reduction in the corporate tax rate on the rate proposals in those proceedings and to address any double recovery resulting from the Commission’s current income tax allowance and rate of return policies. The comment period with respect toprovide re-calculated initial rates for service on the proposed rules extends until April 7, 2017.pipeline facilities. FERC may enact other regulations or issue further requests to pipelines regarding the impact of the corporate tax rate change on the rates. The FERC’s establishment of a just and reasonable rate is based on many components, and the reduction in the corporate tax rate may impact two of such components: the allowance for income taxes and the amount for accumulated deferred income taxes. Because ETP’s existing jurisdictional rates were established based on a higher corporate tax rate, FERC or ETP’s shippers may challenge these rates in the future, and the resulting new rate may be lower than the rates ETP currently charges.

In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of ETP’s interstate natural gas pipelines, including:

Compliance with these requirements can be costly and burdensome. In addition, weETP cannot guarantee that the FERC will authorize tariff changes and other activities weit might propose to undertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations, policies and interpretations thereof may impair the ability of ETP’s interstate pipelines to compete for business, may impair their ability to recover costs or may increase the cost and burden of operation.

Transportation provided on ETP’s common carrier interstate crude oil, NGL and products pipelines is subject to rate regulation by the FERC, which requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If ETP proposes new or changed rates, the FERC or interested persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

The primary ratemaking methodology used by the FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. The FERC’s ratemaking methodologies may limit our ability to set rates based on our costs or may delay the use of rates that reflect increased costs. In October 2016, FERC issued an Advance Notice of Proposed Rulemaking seeking comment on a number of proposals, including: (1) whether the Commission should deny any increase in a rate ceiling or annual index-based rate increase if a pipeline’s revenues exceed total costs by 15% for the prior two years; (2) a new percentage comparison test that would deny a proposed increase to a pipeline’s rate or ceiling level greater than 5% above the barrel-mile cost changes; and (3) a requirement that all pipelines file indexed ceiling levels annually, with the ceiling levels subject to challenge and restricting the pipeline’s ability to carry forward the full indexed increase to a future period. The comment period with respect to the proposed rules extends untilended March 17, 2017. FERC has not yet taken any further action on the proposed rule. If the FERC’s indexing methodology changes, the new methodology could materially and adversely affect our financial condition, results of operations or cash flows.

Under the EPAct of 1992, certain interstate pipeline rates were deemed just and reasonable or “grandfathered.” Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must,

If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business and results of operations.

ETP’s midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still significantly affects their business and the market for their products. The rates, terms and conditions of service for the interstate services they provide in their intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. ETP’s HPL System, East Texas pipeline, Oasis pipeline and ET Fuel System provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than ETP’s costs of service, their cash flow would be negatively affected.

ETP’s midstream and intrastate gas and oil transportation pipelines and their intrastate gas storage operations are subject to state regulation. All of the states in which they operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The states in which ETP operates have ratable take statutes, which generally require gatherers to take, without undue discrimination, production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, ETP’s businesses may be adversely affected.

ETP’s intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the TRRC. Texas gas utilities must publish the rates they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law unless challenged in a complaint.

ETP is subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see description of federal and state pipeline safety regulation below). Violations of state laws, regulations, orders and permit conditions can result in the modification, cancellation or suspension of a permit, civil penalties and other relief.

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.

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.

Pursuant to authority under the NGPSA and HLPSA, as amended, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect HCAs which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas.

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 MarchApril 2016, PHMSA announcedpublished 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

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. More recently, inEffective April 27, 2017, maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $209,002 per day, with a maximum of $2,090,022 for a series of violations. In June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural

gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of natural gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as further amended by the 2016 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require ETP to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in ETP incurring increased operating costs that could be significant and have a material adverse effect on ETP’s results of operations or financial condition.

ETP’s operations arebusiness is subject to stringent federal, tribal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for ETP’s operations,the construction and operation of our pipelines, plants and facilities, result in capital expenditures to manage, limit, or prevent emissions, discharges or releases of various materials from ETP’s pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution resulting from ETP’s operations.construction and operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective obligations, the occurrence of delays in permitting and performancecompletion of projects, and the issuance of injunctive relief. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or released, even under circumstances where the substances, hydrocarbons or wastes have been released by a predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property and natural resource damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or wastes into the environment.

ETP may incur substantial environmental costs and liabilities because of the underlying risk arising out of its operations. Although we have established financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased remediation costs, liabilities or natural resource damages that could substantially increase our costs for site remediation projects. Accordingly, we cannot assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.

Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on ourETP’s operations or financial position. For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the United States counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for the remaining areas of the United States not addressed under the November 2017 final rule in the first half of 2018. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could apply to ETP’s customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new emission

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations.

Along with other refiners, manufacturers and sellers of gasoline, Sunoco, Inc. is a defendant in numerous lawsuits that allege methyl tertiary butyl ether (“MTBE”) contamination in groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance, trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to Sunoco, Inc. TheseAn adverse determination of liability related to these allegations or other product liability claims against Sunoco, Inc. could have a material adverse effect on our business or results of operations.

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 U.S.,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.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on ETP’s business, financial condition, demand for ETP’sits services, results of operations, and cash flows. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. Finally, some scientists have concluded

that increasing concentrations of GHG in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climate events that could have an adverse effect on ETP’s our assets.

Congress has adoptedProvisions 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”), a comprehensive financial reform legislation that establishesthe SEC and other prudential regulators establish federal oversight and regulation of the physical and financial derivatives, including over-the-counter derivatives market and entities, such as us, that participateparticipating in that market. This legislation was signed into law by President Obama on July 21, 2010 and requires the Commodities Futures Training Commission (“CFTC”), the SEC and other regulators to promulgate rules andWhile most of these regulations implementing the new legislation. While certain regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing and we cannot yet predict the ultimate effect of the rules and regulations on our business.

In October 2011, theThe CFTC has also issued regulations to setre-proposed speculative position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. However, in September 2012, the CFTC’s position limits rules were vacated by the U.S. District Court for the District of Columbia. In November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions forequivalents, although certain bona fide hedging transactions. Astransactions would be exempt from these new position limit ruleslimits provided that various conditions are not yet final, the impact of those provisions on us is uncertain at this time.

The Dodd-Frank Act requires that certain interest rateclasses of swaps be cleared on a derivatives clearing organization and credit default swaps for mandatorytraded on a DCM or other regulated exchange, unless exempt from such clearing and exchange trading.trading requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The associated rules require us, in connection with covered derivative activities, to comply with suchCFTC and prudential regulators have also adopted mandatory margin requirements or take steps tofor uncleared swaps entered into between swap dealers and certain other counterparties. We currently qualify for an exemption to such requirements. We must obtain approval from the board of directors of our General Partner and make certain filings in order to rely on theupon an end-user exception from the mandatorysuch clearing and margin requirements for the swaps enteredwe enter into to hedge our commercial risks. TheHowever, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirements to other market participants, such as swap dealers, may changeadversely affect the cost and availability of the swaps that we use for hedging. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing and exchange trading.

In addition to the Dodd-Frank Act, requires thatthe European Union and other foreign regulators establish margin rules for uncleared swaps. The application of such requirements to other market participants, such as swap dealers, may changehave adopted and are implementing local reforms generally comparable with the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact our liquidity and reduce cash available to us for capital expenditures, reducing our ability to execute hedges to reduce risk and protect cash flow.

Some of ETP’s operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas pipeline and other facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Virtually all of ETP’s operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.

If one or more facilities that are owned by ETP or that deliver natural gas or other products to ETP are damaged by severe weather or any other disaster, accident, catastrophe or event, ETP’s operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply ETP’s facilities or other stoppages arising from factors beyond its control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by ETP’s operations, or which causes it to make significant expenditures not covered by insurance, could reduce ETP’s cash available for paying distributions to its Unitholders, including us.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, ETP may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If ETP were to incur a significant liability for which it was not fully insured, it could have a material adverse effect on ETP’s financial position and results of operations, as applicable. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

The United States government has issued warnings that energy assets, including the nation’s pipeline infrastructure, may be the future target of terrorist organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our facilities or pipelines. Any such terrorist attack on ETP’s or Sunoco LP’s facilities or pipelines, those of their customers, or in some cases, those of other pipelines could have a material adverse effect on ETP’s or Sunoco LP’s business, financial condition and results of operations.

In recent years, the federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies of the U.S.United States Department of the Interior, have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any uncertainties or inconsistencies in decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts.

In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional costs, delays, restrictions, or obligations with respect to oil and natural gas exploration and production operations conducted offshore by certain of ETP’s customers. For example, in April 2016, the BOEM published a proposed rule that would update existing air-emissions requirements relating to offshore oil and natural-gas activity on federal Outer Continental Shelf waters. However, in May 2017, Order 3350 was issued by the Department of the Interior Secretary Ryan Zinke, directing the BOEM to reconsider a number of regulatory initiatives governing oil and gas exploration in offshore waters, including, among other things, a cessation of all activities to promulgate the April 2016 proposed rulemaking (“Order 3350”). In addition, in September 2016, thean unrelated legal initiative, BOEM issued a Notice to Lessees and Operators (“NTL #2016-N01”) that would bolster supplemental bonding procedures forbecame 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 wells, platforms, pipelines,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, other facilities. These regulatory actions, currently, this NTL’s implementation timeline has been extended indefinitely beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. The April 2016 proposed rule and NTL #2016-N01, should they be finalized and/or implemented, as well as any new rules, regulations, or legal initiatives could delay or disrupt our customers operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to incur penalties, or shut-in production or lease cancellation. Also, if material spill events were to occur in the future, the United States or other countries could elect to issue directives to temporarily cease drilling activities offshore and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and gas exploration and development. The overall costs imposed on ETP’s customers to implement and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental bonding amounts, which could result in the incurrence of additional costs to complete. We cannot predict with any certainty the full impact of any new laws or regulations on ETP’s customers’ drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. The occurrence of any one or more of these developments could result in decreased demand for ETP’s services, which could have a material adverse effect on its business as well as its financial position, results of operation and liquidity.

The petroleum products that we store and transport through Sunoco Logistics’ETP’s operations are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal facilities and could require the construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

In addition, our butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our ability to recover the costs incurred to acquire and integrate our butane blending assets.

As of December 31, 2016,2017, approximately 6%5% of our workforce is covered by a number of collective bargaining agreements with various terms and dates of expiration. There can be no assurances that Panhandle or Sunoco, Inc. will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results of operations or cash flows.

Federally mandated standards for use of renewable biofuels, such as ethanol and biodiesel in the production of refined products, are transforming traditional gasoline and diesel markets in North America. These regulatory mandates present production and logistical challenges for both the petroleum refining and ethanol industries, and may require us to incur additional capital expenditures or expenses particularly in our retail marketing business. We may have to enter into arrangements with other parties to meet our obligations to use advanced biofuels, with potentially uncertain supplies of these new fuels. If we are unable to obtain or maintain sufficient quantities of ethanol to support our blending needs, our sale of ethanol blended gasoline could be interrupted or suspended which could result in lower profits. There also will be compliance costs related to these regulations. We may experience a decrease in demand for refined petroleum products due to new federal requirements for increased fleet mileage per gallon or due to replacement of refined petroleum products by renewable fuels. In addition, tax incentives and other subsidies making renewable fuels more competitive with refined petroleum products may reduce refined petroleum product margins and the ability of refined petroleum products to compete with renewable fuels. A structural expansion of production capacity for such renewable biofuels could lead to significant increases in the overall production, and available supply, of gasoline and diesel in markets that we supply. In addition, a significant shift by consumers to more fuel-efficient vehicles or alternative fuel vehicles (such as ethanol or wider adoption of gas/electric hybrid vehicles), or an increase in vehicle fuel economy, whether as a result of technological advances by manufacturers, legislation mandating or encouraging higher fuel economy or the use of alternative fuel, or otherwise, also could lead to a decrease in demand, and reduced margins, for the refined petroleum products that we market and sell.

It is possible that any, or a combination, of these occurrences could have a material adverse effect on Sunoco, Inc.’s business or results of operations.

Our 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.

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.

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 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.

While a subsidiary of BG and LCL havehas received authorization from the DOE to export LNG to non-FTA countries, the non-FTA authorization is subject to review, and the DOE may impose additional approval and permit requirements in the future or revoke the non-FTA authorization should the DOE conclude that such export authorization is inconsistent with the public interest.  The failure by LCL to timely maintain the approvals necessary to complete and operate the liquefaction project could have a material adverse effect on its operations and financial condition.

The anticipated after-tax economic benefit of an investment in our Common Units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investments in ETP dependsand Sunoco LP depend largely on ETP and Sunoco LP being treated as a partnershippartnerships for federal income tax purposes.

If we, ETP or ETPSunoco LP were treated as a corporation, we would pay federal income tax on our taxable income 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 casecash 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 present U.S.United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S.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 U.S.United States federal income tax purposes.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code of 1986, as amended (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S.United States federal income tax purposes.

However, any modification to the U.S.United States federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S.United States federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any 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.

We have subsidiaries that will be treatednot requested a ruling from the IRS with respect to our treatment as corporations for federal income tax purposes and subject to corporate-level income taxes.

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 Schedule K-1information statement to each unitholderUnitholder and former Unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our Unitholders and former Unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current Unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such Unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our Unitholders might be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Because we cannot match transferors and transferees of Common Units and because of other reasons, we will adopthave adopted depreciation, depletion and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of Common Units and could have a negative impact on the value of our Common Units or result in audit adjustments to tax returns of our Unitholders. Moreover, because we have subsidiaries that are organized as C corporations for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary having a greater tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our Unitholders.

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,

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.

In determining the items of income, gain, loss and deduction allocable to our, Sunoco LP’sWhen we issue additional units or ETP’s unitholders,engage in certain other transactions, we must routinely determine the fair market value of our respective assets.assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our general partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our Sunoco LP’s or ETP’s common units as a means to measure the fair market value of our respectiveassets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge theseour valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and the resultingintangible assets, and allocations of income, gain, loss and deduction.deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount character, and timing of taxable income or loss being allocated to our Unitholders, Sunoco LP’s Unitholders or the ETP Unitholders.unitholders. It also could affect the amount of gain on the sale of Common Unitscommon units by our Unitholders, Sunoco LP’s Unitholders or ETP’s Unitholdersunitholders and could have a negative impact on the value of our Common Units or those of Sunoco LP and ETPcommon units or result in audit adjustments to the tax returns of our Sunoco LP’s or ETP’s Unitholdersunitholders without the benefit of additional deductions.

In general, our unitholders are entitled to a deduction for the following:

A description of our properties is included in “Item 1. Business.” In addition, we own office buildings for our executive offices in Dallas, Texas and office buildings in Newton Square, Pennsylvania and Houston, Corpus Christi and San Antonio, Texas. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.

Substantially all of our subsidiaries’ pipelines, which are described in “Item 1. Business”Business,” are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. Our subsidiaries have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our subsidiaries’ pipelines were built were purchased in fee. ETP also owns and operates multiple natural gas and NGL storage facilities and owns or leases other processing, treating and conditioning facilities in connection with its midstream operations.

Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other refiners, manufacturers and sellersmembers of gasoline,the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, typically include water purveyors and municipalities responsible for supplying drinking water andstate-level governmental authorities. The plaintiffs primarilyentities, assert product liability claims and additional claims

Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of materials into the environment or protection of the environment. While we believe that even if any one or more of the environmental proceedings listed above were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report environmental governmental proceedings if we reasonably believe that such proceedings will result in monetary sanctions in excess of $0.1 million.

For a description of other legal proceedings, see Note 11 to our consolidated financial statements.statements included in “Item 8. Financial Statements and Supplementary Data.”

The Parent Company’s common units are listed on the NYSE under the symbol “ETE.” The following table sets forth, for the periods indicated, the high and low sales prices per ETE Common Unit, as reported on the NYSE Composite Tape, and the amount of cash distributions paid per ETE Common Unit for the periods indicated.

As of February 17, 2017,16, 2018, there were approximately 255,000158,922 individual common unitholders, which includes common units held in street name. Common units represent limited partner interest in us that entitle the holders to the rights and privileges specified in the Parent Company’s Third Amended and Restated Agreement of Limited Partnership, as amended to date (the “Partnership Agreement”).

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:

None.

For information on the securities authorized for issuance under ETE’s equity compensation plans, see Item“Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

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.

Energy Transfer Equity, L.P. is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ETE.” ETE was formed in September 2002 and completed its initial public offering in February 2006.

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.

Energy Transfer Equity, L.P. directly and indirectly owns equity interests in ETP and Sunoco LP, both publicly traded master limited partnerships engaged in diversified energy-related services.

At December 31, 2016,January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 2.627.5 million ETP common units, approximately 81.0 million ETP Class H units, and approximately 2.3 million Sunoco LP 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 ETP and Sunoco LP, both of which are publicly traded master limited partnerships engaged in diversified energy-related services, and the Partnership’s ownership of Lake Charles LNG. The Parent Company’s primary cash requirements are for distributions to its partners, general and administrative expenses, debt service requirements and at ETE’s election, capital contributions to ETP and Sunoco LP in respect of ETE’s general partner interests in ETP and Sunoco LP. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of subsidiaries.

In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.

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:

Each of the respective general partners of ETP and Sunoco LP have separate operating management and boards of directors. We control ETP and Sunoco LP through our ownership of their respective general partners.

In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 15.823.7 million newly issued ETP common units.

Distributions on the ETP Series A Preferred Units Redemption

In September 2017, Sunoco Logistics Partners Operations L.P., a subsidiary of ETP, issued $750 million aggregate principal amount of 4.00% senior notes due 2027 and $1.50 billion aggregate principal amount of 5.40% senior notes due 2047. The $2.22 billion net proceeds from the offering were used to redeem all of the $500 million aggregate principal amount of ETLP’s 6.5% senior notes due 2021, to repay borrowings outstanding under the Sunoco Logistics Credit Facility and for cashgeneral partnership purposes.

On November 1, 2016, ETP acquiredJanuary 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana.

In February 2017, Sunoco Logistics formed Permian Express Partners LLC ("PEP"),PEP, a strategic joint venture with ExxonMobil Corp.ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp. contributed its Longview to Louisiana and Pegasus pipelines;pipelines, Hawkins gathering system;system, an idle pipeline in southern Oklahoma;Oklahoma, and its Patoka, Illinois

terminal. Sunoco Logistics’ ownership percentage is approximately 85%. Upon commencement of operationsAssets contributed to PEP by ExxonMobil were reflected at fair value on the Bakken Pipeline, Sunoco Logistics will contribute its investmentPartnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment.

In July 2017, ETP contributed an approximate 15% ownership interest in the project, with a correspondingDakota Access and ETCO to PEP, which resulted in an increase in itsETP’s ownership percentageinterest in PEP. Sunoco LogisticsPEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP will beis reflected as a consolidated subsidiary of Sunoco Logistics. ExxonMobil Corp.’sthe Partnership. ExxonMobil’s interest will bein PEP is reflected as noncontrolling interest in Sunoco Logistics’the consolidated balance sheet.sheets.